Good day, ladies and gentlemen, and welcome to the Diamondback Energy and Viper Energy Partners First 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 instructions will be given 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, Manager of Investor Relations. Sir, you may begin.

Thank you, Andrew. Good morning and welcome to Diamondback Energy and Viper Energy Partners joint first quarter 2016 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; 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 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. 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 over to Travis Stice.

Thank you, Adam. Welcome, everyone, and thank you for listening to Diamondback and Viper Energy Partners first quarter 2016 conference call. During the first quarter of 2016, commodity prices tested lows not seen in the past several years. As such, and consistent with our strategy of capital discipline and maximizing stockholder returns, we slowed our 1Q completion activity and now have an inventory of nearly 30 drilled but uncompleted wells. As a result of increased activity associated with running a third drilling rig longer than we initially anticipated and recently picking up an additional frac crew, we are raising the low end of our full year guidance to 34,000 BOEs per day from 32,000 BOEs per day. We anticipate some lumpiness in the second quarter production with the response from completions associated with the second frac crew expected in the second half of this year. Should crude prices continue to strengthen, we could pick up a fourth horizontal rig early in the third quarter. Alternatively, if prices soften from current levels, we could stay at three drilling rigs or less and again moderate the pace of completions. With over $230 million in cash and an undrawn credit facility, we're well-positioned to increase activity levels without stressing the balance sheet. When you compare our current financial position to nearly two years ago when oil price was at its peak, our balance sheet is now stronger, we have more liquidity and higher credit ratings. I'm proud that we've been able to become even stronger financially during the past year. Also, we continue to lower well costs and operating expenses through efficiency gains, optimization, and cost concessions. Our execution metrics continue to improve across the board, even as we begin development in new areas like Howard and Glasscock Counties. All-in cash costs for the quarter, including LOE, G&A, transportation and production taxes, are currently below $10 per barrel, demonstrating how lean and efficient the Diamondback organization operates. We are pleased with the performance of our first five Glasscock County completions, which are exceeding our expectations at the time of the acquisition. This week, we intend to begin completion of wells in our new core area in Howard County, where offset activity remains very encouraging. We expect to see more opportunities to grow our company and believe our proven track record of execution and low-cost operations makes us a natural consolidator within the Permian Basin. While we evaluate all deals in the Permian, we will only do transactions that we believe are accretive to our stockholders. I'll now turn the call over to Mike.

Thank you, Travis. Diamondback continues to post encouraging results and achieve new company execution records. Slide seven shows that on average our Glasscock County wells are tracking a 1 million BOE type curve. Our Riley wells were completed using a higher sand concentration and early production time results for these wells are very encouraging. Slide eight shows pure activity in Howard County, where we will begin completing our first three-well pad this week. As a reminder, we have drilled two pads that target the Lower Spraberry, Wolfcamp A, and Wolfcamp B intervals. Slide 10 shows that Diamondback continues to drill wells faster than offsetting peers in all of our core operating areas. During the first quarter of 2016, we drilled a 9,800-foot lateral well in Howard County in less than 11 days from spud to TD. We also drilled a 7,300-foot lateral well in Spanish Trail in under 10 days from spud to TD, a new company record in Midland County. Lastly, in April 2016, we drilled two wells with 10,000-foot laterals in Andrews County in 25 days from spud of the first well to rig release of the second. Slide 11 shows our current realized well cost reductions, which have come down roughly 35% since the peak in 2014 and approximately 5% quarter-over-quarter. Leading edge drill, complete and equip costs are trending below $5 million for a 7,500-foot lateral well and between $6 million and $6.5 million for a 10,000-foot lateral well. Slide 12 shows reductions to our current realized lease operating expenses since the peak in 2014. We are extremely proud of our production organization for continuing to lower operating expenses. We have reduced LOE from over $8 a barrel in the first quarter of 2015 to $5.23 per BOE in the first quarter of 2016 due to reduced cost and further improved pumping practices. As a result, we have lowered our LOE guidance to $5.50 to $6.50 per BOE from a prior range of $6 to $7 per BOE. With these comments now complete, I'll turn the call over to Tracy.

Thank you, Mike. Diamondback's first quarter 2016 adjusted net income was $2 million, or $0.02 per diluted share. Our consolidated adjusted EBITDA for the quarter was $60 million. Our first quarter 2016 average realized price per BOE, including hedges, was approximately $27. During the quarter, our cash G&A costs were $1.33 per BOE, while non-cash G&A was $2.39. During the quarter, our capital spend for drilling, completing and equipping wells was $76 million. Our infrastructure costs were $5 million, and we paid $4 million on our non-operated properties. A portion of first quarter capital was related to fourth quarter 2015 activities. We spent an additional $19 million on acquisitions during the first quarter of 2016. Diamondback is in an enviable position as a company that has a stronger balance sheet, more liquidity and a higher credit rating than it did when oil was at its peak. At the end of March 2016, we were undrawn on our secured revolving credit facility. With over $230 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 annualized first quarter 2016 EBITDA is 1.1 times, as shown on slide 13. Our practice of limiting our commitment to a portion of our borrowing base again reflects our track record of financial discipline. Moving to slide 14, we provide our guidance for 2016. As announced last night, we increased our 2016 production guidance to a range of 34,000 BOE per day to 38,000 BOE per day. As a result of picking up a second dedicated completion crew, we now expect to complete a range of 35 to 70 gross wells. We have also lowered our 2016 LOE guidance range to $5.50 to $6.50 per BOE from a prior range of $6 to $7. I'll now turn to Viper Energy Partners, which announced a cash distribution last night of $0.149 per unit for the first quarter. Viper has no minimum quarterly distributions or complex ownership hierarchies. The majority of cash flow is returned to unitholders through quarterly distribution providing upside when oil prices rebound. Spanish Trail remains one of the most economic areas in the Permian Basin and we expect the operators will complete their backlog of over 20 DUCs with continued strength in oil prices. At the end first quarter 2016, Viper had $43 million drawn on its revolver. I'll now turn the call back over to Travis for his closing remarks.

Thank you, Tracy. Diamondback again delivered a strong quarter, demonstrating what we do best: reduce costs and expenses, improve execution, and demonstrate capital flexibility in response to commodity prices. We've gotten stronger financially and are poised to accelerate into an oil price recovery. We are pleased with the early well results in Glasscock County and continue to be optimistic about Howard County potential. We look forward to sharing our initial Howard County results in the upcoming quarters. Operator, please open the line for questions.

Certainly. And our first question or comment comes from the line of Neal Dingmann with SunTrust. Your line is now open.

Morning, everyone. Nice quarter again. Travis, for you or the guys there, just how do you think about when you (10:50) these days about an optimal well either in Howard, Glasscock, or obviously the Spanish Trail in relation to sand per foot lateral length? I guess kind of a lot of people are obviously throwing a lot more sand at it. I'm just wondering maybe in those particular things, how you think about let's just stick with lateral length and amount of sand you're looking at?

Sure. Well, the lateral length question is a little easier and I think it's also more well understood, longer is certainly better. In fact, here in a couple of months, Diamondback is going to be drilling our first 13,000-foot laterals. On sand per foot, we continue to test and follow the industry in putting more sand per foot. Our current average is running around 1,600 pounds per foot. We've got some tests that are coming up that will test even higher sand loadings. But in a general sense, we believe that the recipe has an efficient frontier of just the right amount of sand and while we don't know exactly what the answer is, we know it's somewhere, we believe, in that 1,600 pounds per foot to 2,000 pounds per foot.

Okay. And then just last one if I could, how do you think about in either again the three areas just the optimal number of wells per pad? Does that just vary sort of pad per pad depending on exactly how contiguous the acreage, or what do you think about it, is that a three well, four well, or can you – will you start to even accelerate that as conditions improve?

Yes, so, Neal, I believe, if you're just looking for planning purposes, probably three wells, three stacked wells per pad, and then we'll move across depending on the density and the way we stagger the wells, somewhere between six and eight wells across the section. Certainly, we are very comfortable with three or more zones in Glasscock and Howard County and as we've seen in Midland County and some of the other areas, we've got potential for the Middle Spraberry and even the Jo Mill/Spraberry as well.

All right. Thank you, all.

Our next question or comment comes from the line of John Nelson with Goldman Sachs. Your line is now open.

Good morning, and congratulations on the quarter.

Thanks, John.

Yes, when I look at your slides, you guys put rig ranges of two to three for $30 to $45 a barrel and three to four at a $45 to $55 per barrel. You mentioned in your remarks you could add back a rig in early 3Q. I'm just curious is this a function of seeing continued improvement from well economics or is this just a view that oil prices will continue to move higher?

Yes, John, it's actually a little bit of both, but I think the reason we leave that range out there is because we want to be able to respond when we see strengthening oil prices. We've got $45 to $55, we'll say we run three to four rigs. Our rate of returns for all these wells, particularly in Midland County, are ranging somewhere between 50% and 100% rate of return. So we've got a lot of opportunities to drill extremely high rate of return wells. So, we're not looking for economic improvements and we're not looking for well costs to be down from where they are now to help make the decisions. We're really focused on the macro conditions on our oil market and then the near-term price forecast to make those decisions. But again, consistent with what we've always done and said, when returns to our investors are going up, we accelerate into that environment.

That's helpful. And then just, can you remind us, on the fourth rig, would that be reactivating a rig that's already under contract, or would you guys be actually contracting a new rig? And if it's the latter, what sort of term would you be looking to lock up potentially?

John, it'd be a reactivation of a well we currently – of a rig we currently have warm stacked on one of our locations.

Okay. And then I had just one high-level question, if I could. When you think about acquisitions, do you look as hard at Delaware Basin assets, or do you think that maybe Diamondback doesn't currently have sufficient scale or the well economics would be inferior that you don't want to stay continued to focus on the Midland Basin?

We continue to look at numerous opportunities in Delaware Basin. What I talk to my business development group about is as we look at different opportunities, are we upgrading our portfolio? In other words, and said simply, is the average well in the new opportunity at or above the midpoint of the well in our current portfolio? And if it's not, it feels like a dilution to our inventory, and at this point those treads are hard for us to do. But no, we're certainly continuing to look not only – everywhere in the Midland Basin, but also in the Delaware.

Is there a certain scale you think you'd need to be to move into the Delaware? Or is it simply if those assets are above the average of the portfolio you could bolt on even smaller levels?

Yes, it really gets back to the economics of the decision. At what price and what returns do we think we can generate our shareholders, and then secondary or tertiary down the line is what size it is.

All right. That's very, very helpful. I'll let somebody else jump on.

Thanks, John.

Our next question or comment comes from the line of Michael Glick with JPMorgan. Your line is now open.

Morning.

Good morning, Mike.

So several operators are testing multiple down spacing concepts in the Lower Spraberry in and around your acreage. Could you speak to your view on how well density ultimately plays out in that zone? And then also, do you see the potential for multiple benches (16:43) move into your Northern acreage?

Mike, we believe that the testing that's going on in (16:54) right now is appropriate. We're testing down spacing as well and we intend to be fast followers on that. I think you have to be careful in down spacing based on our industry's experience to avoid over-capitalizing a section. That being said, though, we've got to put the drill bit tighter and in more laterals to come up with that ultimate final answer. And we're doing it, other operators are doing it as well, and it's sort of one of those stories that is going to be evolving. We tend to be a little bit more cautious, but certainly as well densities increase and additional stacked pays are tested, that rising tide lifts all the ships here in the Northern Midland Basin.

All right. And then from a high level, you guys continue to improve on both the efficiency and productivity side. Maybe could you speak to kind of what inning do you think we're in from Diamondback's perspective on both fronts?

I think the remarkable thing about the Permian Basin, and I think we're in our 95th year since our discovery well, is that we're almost a basin that's perpetually in the third or fourth inning. And that's because there's just so much hydrocarbons in the strat column that things like technology improvements, horizontal drilling, fracking technologies, all of those things perpetually bring you back in the third or fourth inning. As I sit here today and I look at our costs and our execution and I look at our operations organization and say can you give me more, it feels like, unless there's a substantial technological breakthrough, that we're getting close to the bottom in costs and close to the maximum in efficiencies. But that doesn't mean from Diamondback's perspective we won't continue to push and where a couple of years ago we were probably saving quarters and dimes, right now we're picking up pennies. And every little bit matters. And it's just a remarkable basin to be developing, the Permian is, with all the oil that's in place.

And then last one from me, could you just speak to the service industry's capacity to respond to accelerating activity in the Midland Basin?

Mike, I think obviously the calls that the public service guys are making, they're best equipped to respond to that. I think if the industry was to all of a sudden mash the accelerator completely to the floor and stand up 100 drilling rigs in the Permian Basin, we would have a hard time, I would believe, on the pressure pumping side, immediately responding to that. But if we do a prudent build into a new norm of drilling rigs, I mean we're running, what, less than 130 rigs out here in the Permian right now, and that's down from 560 just a few years ago. If we build into that environment, I believe our service – the service sector, our business partners can appropriately build their organizations back up to respond to the operators' needs. That's certainly the conversations I have with my business partners at Diamondback.

Appreciate the color. Thank you.

Our next question or comment comes from the line of Gordon Douthat with Wells Fargo. Your line is now open.

Yes, thanks. Good morning, everybody. Somewhat related question on the completion side, and well going back to your presentation, I guess you indicated some pretty good efficiencies on the drilling side, I should say, and I was just trying to get a sense on the completions. How much are the completions impacted by efficiency gains, and to what extent are those sustainable in an upturn where industry's adding rigs and drilling more wells?

Probably a little bit different than what we see on the drilling side, the majority of the costs that are associated with completion are tied up with the pressure pumping. And the pressure pumping guys, as commodity prices call for increased activity, they're going to have to go and repair their balance sheets, and so I anticipate costs increasing at some point in the future, probably not in the next quarter or so, but some point in the future, and as such, most of that will transfer right back to the operators. So, are we doing things on the completion side to make our completions more efficient? Absolutely, we are. But I would say to a larger degree on the pressure pumping side, we're relying on our business partners to provide fair prices at good services.

Okay. Makes sense. And then another question I had was just given the results in Glasscock look pretty solid, how do they compare to your initial expectations? And then given the 1 million barrel a day type curve, give or take, how do those wells compete within the portfolio now?

Well, certainly the wells are in the top quartile of our portfolio, at least certainly in the Wolfcamp A. We've been extremely pleased with the Wolfcamp A, and it's competing now with – almost competing with some of our wells in Midland County, some of the Lower Spraberry wells in Midland County. The Lower Spraberry that we tested, which was – there weren't a lot of data points in this portion of Glasscock County in the Lower Spraberry, and as I reported in my last call, we were really pleasantly surprised and I think we've released an IP30 rate in our investor presentation right now that continues to embolden. This is, I think, about 1,125 BOEs a day for an IP30. So again, that was a very strong Lower Spraberry well, and that'll be in the top quartile of our portfolio as well. So both the Wolfcamp A and the Lower Spraberry are well above our expectations at the acquisition time. The Wolfcamp B is about in line with our expectation. So, two out of the three zones are significantly above our expectations. So on average it makes the whole strat column look better.

Okay. And you put these on ESP?

Yes, what we've decided to do early on in our development scenario is as we move into areas which we feel have strategic significance to us that we want to try to eliminate as many variables as we can, and whether it's in Glasscock County or Howard County, the initial wells that we put in there we always put on ESP and that way that allows us to compare ESP performance in the way that the flowing bottom oil pressure declines over time to wells that we do have a good control like in Midland County. So, we believe that that's the best way to do it initially. Are there applications for gas lift? Absolutely, there are. You probably save maybe as much as $100,000 to $150,000 per well. But they do have a little bit more operational uncertainties with them as opposed to an ESP. And just one other point on the ESP that my operations guys continue to remind me, is that as we move into areas where we have a dense spacing of horizontal wells and we frac and we put frac water in the offset wells, it's a whole lot easier to go back out there and turn the rheostats up, speed up the sub pumps and pull the water out of the section. And so overall this whole section starts producing oil sooner than it did, sooner than it would have had we had those wells on gas lift. So there is an economic offset, positive offset, to the increased upfront costs.

All right. Appreciate the color. Thanks.

Our next question or comment comes from the line of Kashy Harrison with Simmons & Company. Your line is now open.

Good morning. Thanks for taking my questions. Excellent work on just bringing down costs on a quarter-over-quarter basis with the well costs now trending below $5 million, was wondering if you could just provide some color on some of the drivers of the cost reductions relative to what you presented last quarter. And then just thinking about a recovering commodity environment, how much of this cost, how much of those savings do you think are sustainable? So for example, for the 7,500-foot lateral wells, if they cost $5 million today, in a $50 to $60 environment, what do you think that moves up to?

Kashy, this is Mike Hollis. I'll try to answer both of those for you. On the cost front, a lot of the savings are coming from some of the optimizations on the drilling side as well as some pricing that we are getting on the pressure pumping side. We're seeing about, quarter-over-quarter, about 5% reduction in cost of goods and services; pipes, steel iron that we buy and use in the wells. But as far as the drilling side, it's typically speed with which we drill, modified case and designs, where we're running shallower casings. And then on the pressure pumping side, it's current pricing that we're getting from the industry right now. As far as the stickiness of this current price environment, as we all get back to work in the next few quarters, until the iron gets utilized out of the yard, I think we will continue to see these lower prices stick around for a while. But as the other basins tend to pick up work, so whether it's $50, $60 oil and the Eagle Ford and the Bakken start getting to work, you'll start seeing these guys have to raise their prices, because they have a lot more competition for the iron.

Thanks for the color there. And on the operating expense side of things, in one of the slides, you highlighted that 90% of oil productions is going to be on pipe by the end of the year and 80% of the water will be piped to saltwater disposal. Could you maybe just shed some color on what LOE may look like by the end of this year on a per barrel basis?

You bet. The oil pipeline, that's more of in our realized prices that we see. The water side, again, every time we come into a new area, that's one of the first things we do, is build the infrastructure out for both supply and removal of fluids from the wells. So as we go forward again, a lot of it's going to depend on the volume forecasts and what oil prices do, but if we keep a fairly flat oil price, it will be fair to say that we should have fairly flat LOE for what we have in our guidance. If oil prices pull back and we pull back activity and migrate to the midpoint of our production range, you'll see those LOE costs go up slightly.

Got it. And just shifting gears to Viper, I was just wondering if you all could shed some light on the current A&D market in the mineral space. If there's any color you can shed there?

Yes, and we don't typically like to talk about acquisitions that we have under current evaluation, but I can just say in a general sense, that the deal flow on the Viper side has moved up materially late last year and through the first quarter of this year. So Viper is fully engaged in trying to deliver some accretive deals to its unitholders.

Okay. Well, thanks for the color, there, and thanks for taking my questions. I really appreciate it.

Thank you.

And our next question or comment comes from the line of Jason Wangler with Wunderlich. Your line is now open.

Hey. Good morning, guys. Mike, you may have touched on it a bit there, but was just curious, the slide 10 that shows obviously the really solid days of drilling, it seems to me at least that as you look at those graphs, specifically Howard and Glasscock, that the first, call it, 8,000 feet, basically the vertical portion of that well really gets down a lot quicker than all the peers. I think you mentioned the shallower casing in a previous answer. But was just curious if there's something operationally different that you guys are seeing there, for lack of a better word, gives you guys a really good head start getting these wells down quicker?

In general, the modified casing design is more in the Western side of the basin. We're very early into Howard and Glasscock. So we'll continue to push the envelope there. So you're not really getting that benefit yet in those areas. What you're seeing here is just blocking and tackling that we do every day. It's good research in the area and it's just good drilling practices that we try to employ. I wish I could say there was secret sauce to being able to deliver that kind of performance, but it's essentially just good hard work from the guys in the field.

Okay. I appreciate it. And then just maybe for Tracy, just on the tax side, just kind of cleaning up some numbers, obviously there wasn't any effective tax rate this quarter. Is the thought process going forward, maybe just for modeling purposes what we should be looking at?

Yes, I would suggest that internally I'm modeling no taxes for the remainder of this year. This is a result of the impairments we had been booking over the last few quarters as prices start to flatten out over the last really 12 months we could get back into a tax position, but I don't foresee that until probably 2017.

Okay. I appreciate it. Thank you very much.

Our next question or comment comes from the line of Tim Rezvan with Sterne Agee. Your line is now open.

Hi. Good morning, folks. Thanks for taking my question. I was hoping to change gears a bit and ask about differentials, if we look at both Diamondback and Viper, we've seen kind of some volatility across all hydrocarbons. I know that Viper has other operators kind of producing some of its barrels. But can you kind of explain what that variability was and maybe give us a thought on what we can expect the rest of the year?

Tim, I'm not sure that we've specifically studied that specific question. I can tell you that we've got guidance in there both at the Viper level and the Diamondback level that I would anticipate kind of what you've seen is more consistent what we're going to see going forward.

Okay. So there's nothing on the NGL sort of processing side or regarding ethane to drive kind of realizations for the first quarter?

Yes, I mean, there's a couple things. I mean, one is the amount of ethane rejection that does affect that. The other thing is, as prices get lower, you've got fixed T&S fees. So as prices get lower, it makes your differential look bigger. So hopefully we've got some price improvement on the NGL side, that differential will go down as well.

Okay. Okay. That's fair. Just you saw $0.35 deterioration from 4Q to 1Q in gas for FANG, and kind of similar move down for Viper. That's all. Okay, I'll leave it there. Thanks.

Our next question or comment comes from the line of Brian Downey with Nomura Securities. Your line is now open.

Great. Nice quarter, guys. Thanks for taking my question. Just quick one, given that first quarter production came in at the high end of the full year guidance, can you just give us a sense of how we should think about the general production trajectory towards the rest of the year? I know you'd mentioned a lumpy second quarter, but just curious as to how we should think about the moving parts as we head into the back half of the year.

Sure. I think as Adam explains it, when we talk about it internally, we look at our production more in a J-shape recovery with most of the completions as I outlined with the second frac crew impacting 3Q and 4Q. That being said, though, we have to be a little careful on thinking what we're going to do quarter-over-quarter, because we don't guide to the quarter. One of the reasons is because we can move into a quarter or out of a quarter, a three-well or four-well stacked pad depending on logistics and how quickly we can get to those and if we bring one into a quarter, and they're three-well or four-well pads bringing 3,000 barrels a day or 4,000 barrels a day, you could have a material impact on the quarter. So again, why we stick towards an annual guide is because of that somewhat difficulty in forecasting when these stacked pads come on.

Great. And if I think about the potential for a fourth rig, as you mentioned, should I think about if that's a 3Q event that probably might get a little bit in the fourth quarter but that's more affecting 2017 type volumes?

Yes, that'd be building into a recovering oil price commodity tape and more late this year, maybe exit volumes but primarily 2017.

Great. Thank you.

Our next question or comment comes from the line of Chris Stevens with KeyBanc. Your line is now open.

Hey. Good morning, guys. Travis, maybe I could just touch on the Delaware Basin M&A again. Have you seen acreage out there that you think would be accretive to your average inventory quality? And if so, I guess is it really more a question of valuation at this point or do you think the Delaware just doesn't really compete with what you have on the Midland Basin side?

No, there's portions of the Delaware that we believe can compete. And I'm not saying that's where necessarily the trades are occurring, but in a general sense we just continue to look at the Delaware from Northern Delaware to Southern Delaware and we evaluate it relative to what's currently in our portfolio and try to make good decisions based on that that are going to be accretive to our shareholders. So, probably more a valuation point.

Oh. Okay, got it. And then I guess what are the expectations on Howard County at this point? What you have over in Spanish Trail and now Glasscock both look pretty tremendous. I guess what do you guys think in terms of how Howard County's going to fit into the pecking order at this point?

Well, we updated – what slide's that, Adam? We updated in our slide deck some new well data points for that in Howard County on slide eight. And I made the comment when we acquired this asset about this time last year that this was the most de-risked acquisition Diamondback had ever made. So as you peruse the data that's on slide eight, you can see why we continue to be emboldened on the results from the wells and we're going to be pumping sand down hole here in a few days and we'll have what we believe are some good tests in our October call where we'll at least have a 30-day rate on our first three-well pad and probably some early indications from our second three-well pad. But if you just look at the data over there, it looks pretty strong.

Got it. Thanks a lot.

And our next question or comment comes from the line of John Aschenbeck with Seaport Global. Your line is now open.

Good morning. Thanks for taking my question. Just had a follow-up on extended laterals. A two-part question, really, and that is what percentage of your acreage would you estimate, ballpark figure, is currently amenable to longer laterals, let's call it 10,000-foot plus? And then secondly, how many of 2016's 35 to 70 completions, again, ballpark figure, would you estimate around that 10,000-foot plus range?

I'm going to let Russell answer that question.

Yes, it obviously varies by area, but I think probably we'd say about 70% of our acreage, we can drill 10,000-foot laterals and probably for the wells we'll drill and complete this year I think that number's in the 60% to 65% range. So what's happened is we've been successful in trading acreage and pooling acreage to drill longer laterals because not just us but the rest of the industry wants to. So like our Glasscock acreage, it's probably in that 70%, 10,000-foot laterals and Howard may end up being up a little higher than that.

Perfect. Very helpful. Thanks, guys.

And at this time, I'm showing no further questions. So with that said, I would like to turn the conference back over to Travis Stice, CEO, for closing remarks.

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

Ladies and gentlemen, thank you for participating in today's conference. This concludes the program. You may now disconnect. Everyone, have a wonderful day.