Diamondback Energy Inc (FANG) — Q3 2016 Earnings Call Transcript

Thank you. Good morning and welcome to Diamondback Energy and Viper Energy Partners joint third quarter 2016 conference call. During our call today, we'll reference an updated investor presentation, which can be found on Diamondback's website. We have 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, 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'll 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, Kaes. Welcome everyone and thank you for listening to Diamondback and Viper Energy Partners third quarter 2016 conference call. Diamondback remains optimistic on a commodity price recovery and has continued to reaccelerate the pace of activity by adding a fifth rig in October and plans to add a sixth rig in early 2017 on our recently closed Delaware Basin acquisition and could potentially add a seventh rig in 2017, should conditions warrant. In conjunction with the rig acceleration, we have prudently added hedges to protect against lower commodity prices. We continue to expect the majority of our DUCs to be completed by the end of 2016. Our increased activity levels, combined with continued strong well performance, will enable us to grow production by more than 30%, and sets us up to continue to have multi-year organic growth at or near cash flow at current strip prices. As a reminder, we recently increased our 2016 production guidance range to 41,000 to 42,000 barrels a day, from 38,000 to 40,000 barrels a day, while keeping capital spend guidance unchanged. We have also introduced our 2017 production guidance of 52,000 to 58,000 barrels a day, which represents more than 30% production growth, as I previously mentioned. Diamondback continues to deliver on best-in-class operating expenses and we recently lowered our 2016 LOE guidance to $5.50 to $6.00 per BOE. We are pleased with the continued strength of our well results throughout our asset base, which Mike will elaborate upon later. Our organization continues to reduce DC&E costs. Third quarter 2016 cash operating costs are $9.15 per barrel, including cash G&A that is less than $1 per BOE. As illustrated on slide 5, Diamondback has a track record of accretive acquisitions and continues to evaluate deals in the Permian Basin. As shown on slide 6, we have amassed a robust inventory with five core areas capable of 1 million barrel plus EURs. In each of these areas, we're focused on long lateral development, which will allow us to grow within cash flow for many years. Switching to Viper Energy Partners. Viper recently increased its distribution by 10%, representing about a 6% annualized yield as a result of increased activity and strong well results from its operators. With improving commodity prices, we have seen an increase in deal flow and continue to evaluate additional mineral acquisitions. I'll now turn the call over to Mike.

Thank you, Travis. Diamondback continues to post encouraging results, achieving new company execution milestones. Slide 7 shows Delaware offset results that continue to improve and we now have four different zones that have successfully been tested through the drill bit. We're excited to get to work on our new Southern Delaware leasehold at the beginning of next year. Slide 8 shows two new 10,000-foot Wolfcamp B wells in Glasscock County. The Target 3905WB and 3904WB Wolfcamp B wells achieved an average 30-day flowing IP rate of 1,425 BOE per day, with an 85% oil cut. We also completed a second two-well Wolfcamp B pad with 8,000-foot laterals that averaged a 30-day flowing IP rate of 1,070 BOE per day, also with an 85% oil cut. Two of the four wells completed during the third quarter continue to flow naturally, with all four Wolfcamp B wells producing similarly to our prior Wolfcamp A wells in Glasscock County. These four Wolfcamp B wells are tracking a normalized 7,500-foot lateral type curve of 1 million BOE. Shifting to slide 9. We recently completed a three-well pad in Howard County targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B. These wells had an average lateral length of 9,700 feet. The Reed Wolfcamp A achieved a two-stream 24-hour IP of 2,150 BOE per day with an 89% oil cut, and the Reed Wolfcamp B achieved a 24-hour IP of 1,800 BOE per day with a 90% oil cut. The Lower Spraberry well is currently producing 800 BOE per day with an 89% oil cut and is still cleaning up. The initial data from these wells appear stronger than the company's first three-well pad in Howard County. Early time data from the Phillips-Hodnett wells indicate after a four-month production history, they are tracking a 7,500-lateral type curve of over 1 million BOE in the Wolfcamp A, and nearly 900 MBOE each in the Lower Spraberry and Wolfcamp B. We believe this confirms three distinct economically productive zones on our acreage position. Turning to slide 10, Midland County Lower Spraberry results continue to outperform our 7,500-foot lateral type curve and will continue to be a core development area for years to come. On slide 11, we also highlight another area with investment-class Spraberry resource. In Martin and Andrews County, Lower Spraberry wells are tracking 1 million BOE type curves, which is comparable to our wells in Midland County. We continue to allocate capital to this core development area in 2017. Slide 13 shows Diamondback continues to drill wells at peer-leading levels in all of our operating areas. During the third quarter of 2016, we drilled three wells across the Northern Midland Basin, with an average lateral length of 10,900-foot in an average of 11.5 days each from spud to total depth. We also drilled two wells in Midland County with lateral lengths of more than 13,000 feet, our longest drill to date. Longer laterals increase capital productivity and returns to shareholders, which is why Diamondback continues to block up acreage and drill longer laterals. Our well costs have come down roughly 47% since the peak in 2014. Leading-edge Midland Basin cost to drill, complete and equip wells remain below $6 million for a 10,000-foot lateral well and below $5 million for a 7,500-foot lateral well. Slide 15 shows reductions to our operating expenses since the peak in 2014. Looking back a year, we have reduced our LOE by 24% to $5.37 per BOE in the third quarter of 2016, due to improved pumping practices as well as service cost concessions. Illustrated another way, the first nine months of 2016 versus the first nine months of 2015, we've spent 9% less net dollars on operating costs, while producing 27% more BOE. As a result, we have reduced our LOE guidance range to $5.50 to $6.00 per BOE compared to $5.50 to $6.25 per BOE previously. Diamondback continues to maintain a rate of return focused completion optimization program. We continue to test high-density near-wellbore fracs, diversion agents, nano-surfactants, as well as dissolvable plugs. These tests are ongoing as we continue to weigh the benefits of each technique versus the additional cost. With these comments now complete, I'll turn the call over to Tracy.

Thank you, Mike. Diamondback's third quarter 2016 net income adjusted for non-cash derivatives and impairment was $42 million, or $0.54 per diluted share. Our adjusted EBITDA for the quarter was $102 million. Diamondback's average realized price per BOE, including hedges, for the third quarter was $34.30. During the quarter, our cash G&A costs were $0.88 per BOE, while non-cash G&A costs were $1.52. During the quarter, Diamondback spent approximately $75 million on drilling and completion, $7 million on infrastructure, and $9 million on non-operated properties. We spent an additional $701 million on acquisitions during the third quarter. This included approximately $126 million at the Viper level. In connection with our fall redetermination, Diamondback's lenders approved a $1 billion borrowing base under its credit facility, up 43% from $700 million previously. However, we again elected to limit the lenders' aggregate commitment to $500 million. With over $160 million in cash and an undrawn borrowing base with $500 million in capacity, we have ample liquidity to fund our upcoming activity. As shown on slide 17, Diamondback ended the third quarter of 2016 with a net debt to trailing 12 months adjusted EBITDA ratio of 0.9 times. On slide 18, we provide our guidance for the full year 2016, as well as our preliminary guidance for 2017. In October, Diamondback increased its 2016 production guidance to a range of 41,000 to 42,000 BOE per day, up 6% from July. With strong well performance driving the increased outlook, our 2016 capital expenditure guidance was unchanged at $350 million to $425 million. As part of that update, we also introduced preliminary guidance for the full year 2017. At current strip prices, we expect to deliver annualized production growth of over 30%, at or near breakeven cash flow. I'll now turn to Viper Energy Partners, which announced on October 27 a cash distribution of $20.07 per unit for the third quarter, up 10% from the second quarter of 2016, and represents a nearly 6% annualized yield as of November 7. Operators on Spanish Trail continue to decrease the current DUC backlog. There are 14 DUCs currently on Viper's acreage, including approximately 10 wells that are normal inventory. At the end of the third quarter of 2016, Viper had $54.5 million drawn on its revolving credit facility. In October, Viper's lenders approved a $275 million borrowing base, up 57% from $175 million previously. 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 production is up as a result of well performance and accelerated activity. Costs and expenses were down and we continue to break execution records. We accomplished this while maintaining our fortress balance sheet. Our financial flexibility allows us to respond quickly to prices, and we remain well positioned to bring value forward across our asset base. We are pleased with the early results in Howard and Glasscock counties, increased acquisition activity at Viper, and are excited to begin development in the Southern Delaware Basin. Operator, please open the line up for questions.

Morning, Travis, guys, Tracy. Nice quarter. Say, Travis, two things here. First, you mentioned about maybe perhaps bringing a seventh rig next year. Could you talk maybe just in broad terms, Travis, how you would attack? I mean, now that you've mentioned the great results in Glasscock, Howard, as well as even in Andrews, you had six to seven rigs running, how would you allocate those including the Delaware area?

Sure. So if we got to a seven-rig cadence most likely in the back half of next year, you'd have six rigs working in the Midland Basin and you'd have one rig working in the Delaware. And those six rigs would be allocated between likely one or two in Howard County, one or two in Glasscock, and one or two or three in Midland County, actually two or three in Midland County. And so, the rigs are a little fungible, and one of the reasons that we pointed out that we've got five core areas that are capable of 1 million barrel type EURs is because we believe we've got lots of opportunities to deliver really nice returns to our investors.

And then, Travis, in Howard and – not just Howard, but none of these – many of these areas you talk about, the Wolfcamp A, B, Lower Spraberry, a number of successful intervals. As you're drilling these, are you going to – I know, kind of looking at the Delaware, you were talking about doing mostly just Wolfcamp A. If you now, with your target in the Midland next year, will you do sort of multi-stack or what do you think the focus is going to be when you look at Howard, specifically in Howard and Glasscock?

Yeah, so, Neal, that's a good question and I wish I had a definitive answer for you. I can tell you our current state of thinking is to always drill multi-well laterals. And now whether we drill those all in the A or in A/B and Lower Spraberry, it's still kind of up in the air until we get a little bit more established and seasoned production on our test in Howard County. One thing we do know is that if you're looking for a clear winner on the eastern side of our acreage position, on the eastern side of the basin, it's very definitely the Wolfcamp A. And if you're looking for a clear winner on the western side of our acreage base, including what we talked about this time for the first time really in northwest Andrews and northeast – northwest Martin and northeast Andrews is going to be the Lower Spraberry. So we've really got two zones that are clearly best-in-class, and we believe that the DC&E costs that we're doing right now are probably at an all-time low. And so, we've got really nice 1 million barrel wells that we're bringing online at an all-time low DC&E cost, and we think that's going to drive our production growth next year, as well as staying within cash flow.

Got it. Then just lastly, you all seem to be a bit more full-cycle return driven than some other companies out there, which I like to see. I mean, when you see sort of growth for next year, is it just based on return driven? I mean, I guess the question would be, if you can add more hedges like these others, these 2x1s and lock in some of that, would that cause you to perhaps remain more active even if prices drop? Or maybe just talk about, rather than ask what you guys would do if oil goes up or down, how you think about that including the hedges.

Sure. Neal, we've always talked in times past that we believe hedges as financial engineering tools and we typically disassociate those with real-time operation decisions because you're putting hedges on for the current calendar year and you're producing these wells for another 50 years. That being said though, we believe these creative 2x1 collars that we put in place give us some protection on the downside for at least – to at least allow us to maintain some activity going forward into 2017. Even though with those hedges in place, I think we've got about 13,000 barrels hedged in November-December this year and through the first half of next year. That being said though, our balance sheet, as I mentioned in my prepared remarks, we've got a fortress balance sheet. We've got cash on hand right now. So we've got the ability to continue our rate of return and NPV focused strategy on allocating capital. So, we don't mind accelerating activity into a recovery, and if we continue to see things that indicate commodity prices recovering and our industry recovering, well, yeah, then we can continue to accelerate activity there. Just in the same vein though, if we see price pull back to $35 a barrel or whatever, we have the ability to tap the brakes a little bit as well, too.

Makes sense. Thanks for the detail, Travis.

Thank you, Neal.

Good morning and congrats on another strong quarter of execution.

Thanks, John.

On slide 7 I think you guys incrementally showed a peer result in the second Bone Spring over in the Delaware Basin. I know you included some second Bone Spring credit in your locations when you announced the acquisition. But can you just speak to; is peer activity in the second Bone Spring making you feel any better about the potential to add more locations there? And then if you could after that just remind us the first rig that comes in the Delaware in 2017. What horizons that will target early on?

Sure. When we bought that acquisition, we underpinned it really with two zones, the Wolfcamp A – in the Wolfcamp A, the third Bone Springs and the Wolfcamp B. So those are the zones that we feel like we're de-risked. We recognize that there is upside in the second Bone Springs. And I'm going to let Russell address what we found out about the second Bone Springs since the acquisition time. Specifically to your question on where that rig's going to get allocated, we'll be drilling probably five wells, the first five wells we drill next year in the Delaware Basin will be focused on the Wolfcamp A. We're doing that for lease obligations. And once we've got all of those obligations satisfied, we'll switch to our more traditional development of multi-well pad, and we'll be doing these and third Bone Springs and As all at the same time probably in the back half of next year. Russell, do you want to answer the second Bone Spring question?

Yeah. I mean, obviously, we're more encouraged by the results we have seen out of the second Bone. There's, obviously, a limited number of tests. Based on the analysis we did before the acquisition, we thought there was potential there. And again, we're encouraged by the results that we've seen. But as Travis was saying, our focus will really be on the Wolfcamp and the third Bone. And in one of the early wells we drill there, we'll core the intervals and based on the results of that core and early results, we'll make our decision going forward. But based on offset results in the area, we think the Wolfcamp A is probably the best zone, but we've seen some really nice results out of the third Bone and Wolfcamp B as well.

Great. That's helpful. And then I guess just as my second question, you provided detail on the presentation about how wells are outperforming type curves. As we go into 4Q, should we be expecting any type of curve update alongside the reserve update at year end? Or do you think you'll continue to kind of gather data before potentially making any changes there?

Yeah, John, we've historically been very conservative on our type curve communication. We like to keep two sets of books, kind of a management expectation book and the Ryder Scott books. We always err on Ryder Scott books. The numbers that you hear us quote are Ryder Scott reserve numbers. We do have reviews scheduled between now and the end of the year with Ryder Scott, and I expect Russell and his team to sit down with those guys and we'll see, and we'll communicate whatever those results are when we get them wrapped up. It will probably be sometime in the first quarter.

Perfect. I'll let somebody else hop on. Congrats again.

Thanks, John.

Morning. Just looking at your core operating areas, your spacing assumptions do appear conservative relative to your peers. Can you talk a bit about your thought process on down-spacing and plans to test tighter spacing over the near and intermediate term?

Yeah, just in general, Michael, I'll let Russell talk specifically, but in general, we believe, just like I was talking about on our reserves, we're going to stay conservative on our reserves and we're going to stay conservative on our down-spacing. We've got over 3,000 wells left to drill in our inventory on, as you just pointed out, your opinion of conservative spacing. So if our peers and industry prove up that tighter spacing works, well, then we'll be fast followers, and you'll see our inventory increase dramatically, if you believe some of the numbers that the industry is touting out there in terms of development spacing. In terms of what we're currently doing, we do have numerous tests going on. I'll let Russell talk specifically about those.

Yeah, we've done down-spacing tests in the Lower Spraberry and other zones as well. It's still early. We'll put out with Ryder Scott particularly in the Lower Spraberry, where we – just now actually have a full section of development on tighter spacing, which we think is going to be the real test. Obviously, we did some tests early on where we drilled three-well pads or two-well pads, where the early results were very encouraging. But we think you really have to look at it in a whole section development mode to see what the true results are. And I think we're getting close to having some of those results, and we'll review with Ryder Scott in the next couple of months. And based on our analysis and theirs as well, we'll report what we're seeing.

Got it. And then just with five core operating areas, could you speak to about how many rigs you think that could support over the longer term, and maybe where you are from a people perspective to support that level of activity?

Sure. So in general, this is just kind of a rule of thumb that we use. For every 10,000-acre block, you have, we believe you can operate efficiently with two drilling rigs, and that means you can coordinate accumulation and stimulation fluids, you can coordinate simultaneous operations between drilling and fracking without getting in each other's way. So that's kind of how we've set it up. And if you look across our asset base, you can see each of those core areas. They all average somewhere between 10,000 and 15,000 acres. So notionally inside those circles, you could run two rigs in each of those areas. Oh, and then the question on people, yeah. We're in pretty good shape. We always are looking to add a few key contributors. We tried to build the organization to support a 10-rig program, and we're not far from that right now, but we're always looking for the best and the brightest to come join our team. If we do ramp up, you will probably see a small increase in personnel.

All right. Thanks.

I think we're at about 160 employees right now, including field operations.

All right. Thank you very much.

Good morning, everyone. I was hoping, Travis, on a follow-up to Neal's question on the rig ramp. Could you talk about what your plans are, your thinking is on Delaware longer terms? So beyond 2017 how much activity you expect in the other infrastructure build and other considerations you would have on further increasing activity in the Delaware?

Sure. I'll answer your question on rig ramp, and then I will turn it to Kaes and let him talk about the infrastructure. But from a rig ramp perspective, I'll just reiterate what we talked about during the acquisition time, which is we're going to add one rig per year for the next four years. Now, one of the levers that we can control that drives differential value to our investors is by accelerating that. And if you go to my previous commentary of two rigs per 10,000 acres, we've got roughly 20,000 acres there. So we could get to four rigs sooner pretty efficiently, but we just need to get out there and start drilling. So the corporate line right now is right in line with what we talked about at acquisition, which is a one to four rig ramp over the next four years. Certainly with the results, commodity price, et cetera, we can look to accelerate that. I'll let Kaes give us a thumbnail sketch of where we are in infrastructure out there.

Yeah. On the Delaware, when we bought the transaction, it came with 25,000 barrels a day of salt water disposable capacity, so I think we're good there for the foreseeable future. Fresh water, we're looking to build our own fresh water infrastructure throughout the majority of leasehold, and we're currently in discussions on the midstream side, both oil and gas, with the local providers to dedicate that acreage long term.

Is there any real needs on the gas processing side, or do you feel like that's handled or it's building out?

Yeah, there's significant capacity out there right now that we're going to join up with a couple of private equity-backed guys that are already out there.

Okay. And then on the well performance, it seems to be improving pretty markedly from just a quarter or two ago. Is that consistent with your perspective and if it is, can you identify any single driver that is responsible for the bulk of that improvement?

Yeah. We're always trying to optimize our results either through both landing zone and stimulation. We've talked about – Mike talked about that we've got a lot of different stimulation tests that we've done. Again, most of those are fairly early in the results. I mean, some of the results are fairly encouraging and I think if you looked at our current stimulations on average, we're probably in the 1,600 to 1,800 pound per foot range doing the high-density near-wellbore fracs. With the data we've got so far, again as I said, we think those look encouraging, so we're continuing with those. But as we've mentioned, it'll be based on the returns we're getting for those incremental dollars that we're spending and we'll continue to monitor the results and make changes going forward as appropriate.

Thanks for the color.

Yeah, Drew, just to add one other comment. I just want to reiterate what Russell said. We do a lot of science testing, as Russell just outlined, but I want to emphasize the point that he closed with is that we're trying to assess what we're doing relative to the returns we get for the incremental dollar. So when you hear us talk about results from these different techniques that we're trying, we always underpin it with are we generating a greater return for our investors for the capital expended. And we hope the commentary for the industry navigates that way as well, too. So just wanted to add that. But thanks for your questions, Drew.

Thanks.

Thanks. Good morning. Travis, there's been some concern lately from investors here that you and the other kind of Permian high fliers are growing to, or the activity is back to the point here where you're going to ultimately fill up trunk line capacity coming out of the Permian. And I know you have some opinions on that, so just was hoping to get some color there. And just if there's some concerns at Diamondback on that front, do you have the ability to go out and do some basis hedging today that might protect you? Have you thought of that? Thank you.

Yeah, I'll let, Mike, I'm going to let Kaes answer that question.

Yeah, hey, Mike. We released today that we have 24,000 barrels a day of basis protection for next year, 2017, and 10,000 a day in place for 2018. I think we're looking at it two ways. We're going to protect ourselves operationally by looking at long haul capacity and meeting with some of the top guys coming out of the basin, and two, protecting us financially via those basis hedges. So we're active and we're looking at it.

Okay. Do you have an idea kind of what ballpark the market is for basis in 2018 right now?

It's a thinner market. We put 10,000 barrels a day on at about $0.85. I think we're happy with any number under $1 there in that market.

Okay. Great. And then, Travis, going back to the Lower Spraberry and Howard, I'm just flipping through slides. I guess this is slide 9 and 10 here, and it's encouraging to hear that these first two wells here are tracking 900,000 barrel wells and above. But it does look like the profile is different versus what you are bringing on in Midland, and just we wanted to get a little bit more color on why you have the degree of confidence that these wells will actually reach that EUR level, given the just the early performance. Thanks.

Yeah, I'll let Russell answer it specifically, but in general term let me tell you what we're seeing in the Lower Spraberry. It does appear that it's drawing its own curve, which is atypical for most of the unconventional shales that we produce that come on at a pretty high rate, and then decline pretty quickly. The Lower Spraberry has a much slower time to peak, and the peak seems to be somewhat muted relative to what its peers are in the other shale intervals. But the decline rate is what really has surprised us. It's much, much shallower. And we've got now, as we pointed out in our prepared remarks, we've now got over four months of production history. So when Russell looks at that well, he is not just making an assessment on that one well. He's also incorporating the results from all the other Lower Spraberry wells in Howard County. And Russell, do you want to add anything to that?

Yeah. I mean, for the most part, the profile that we're seeing is fairly typical of the majority of the Lower Spraberry wells in Howard County. And we've done data trades with the other operators, so we've been able to look at their data in detail. And that's what really gives us the confidence that these are much lower decline profiles and that the EUR is going to be good. That said, I mean, we're continuing to try some things to optimize those early-time production rates. We had a micro-seismic survey that we completed on that Reed three-well pad. In the next couple of weeks, we'll be getting all that data in and we'll look to see what occurred during the simulation and we'll make adjustments potentially to both the landing zone and the simulation. And we're fairly optimistic at this point that we can get decent things to get some higher initial rates, but again as we said, we're pleased with what our projected EURs are. And it is fairly early time, but we've got offset operator data that's probably got a year or more of production history in some cases that gives us some pretty good confidence that the EURs are going to be good.

Okay. Great, guys. Thank you.

Good morning and thanks for taking my questions. My first question pertains to service cost and, Travis, just curious what you're seeing right now in the way of any kind of service cost inflation currently. And then as you think about 2017, where do you see things maybe getting tighter? Do you see any inflation out there?

Yeah. I can just tell you, Pearce, from a perspective of modeling the company's forward activity, if we model an increased commodity price, we always model an increased service cost. We think that's the most intellectual way to model the company. That being said, though, if oil stays at the $45 range like it is today, I don't think you are going to see much pressure in 2017. Look, we know our business partners, primarily on the pressure pumping side, need to start generating some profit to regenerate their aging fleets. And we need them there to be able to answer our call when activity levels do ramp up materially. So, with that being said, we just don't see a whole lot of reason on the pressure pumping side for costs to go up in 2017 if we're going to be range-bound in that $45 to $50 barrel world. Rigs, we've got plenty of drilling rigs. No worries there for the foreseeable future. And those are really the two big spend items we monitor the most closely.

Thank you. And then my follow-up pertains to the acquisition environment within the Permian. Just real high level, how do you see it right now? Are there still plenty of deals out there? Do you think valuations maybe need to come down a little bit? But even just some color between the Delaware and the Midland, if you could provide it.

Yeah, Pearce, we've got a pretty consistent record of not talking about transactions that are underway. But I can give you some of my high-level thoughts. If you go back to our ops update, I made the comment that we're only going to do transactions that generate exceptional returns to our investors. I think you can always hold me accountable for that statement. There is still – on the Midland Basin side, we see smaller size trades that are occurring. That, one, are allowing us to block up and drill longer laterals, whether they're outright acquisitions or swaps. And there's a few smaller packages that are out in the marketplace right now that I know haven't garnered a lot of interest. On the Delaware Basin side, just the saturation of private equity companies that are out there that are all trying to take advantage of the marketplace right now, there are just a whole bunch of opportunities there in the Delaware. And I don't know if there is buyer fatigue or not yet in the Delaware, but I can tell you that I don't think all 15 or 20 of the private equity-based companies out there are going to go public in the next 12 months. So they're all looking for some form of liquidity event for their investors. So, like I said in my prepared remarks, Diamondback is in that game. We continue to look for ways to generate exceptional returns to our investors.

Thanks, Travis, and congrats on a solid quarter.

You bet, Pearce. Thank you.

Good morning, guys. I wanted to go back to the enhanced completions that you guys kind of talked about. Can you give us a sense for what kind of the dataset is internally with Diamondback wells as far as kind of the well history and the aggregate dataset and kind of what you're all – obviously, the encouraging results in Howard and some of the other areas, but just kind of wanted to get a greater sense of what the ultimate dataset is internally within Diamondback for those types of wells.

Jeff, this is Mike. We've been doing testing since we started fracking wells out here in 2012 in these horizontals. So, it's a pretty extensive test group and we've changed a lot of things over time. The most recent high-density near-wellbore diversion techniques, that subset group, again, in multiple counties and multiple zones. But roughly 12 to 15 wells very early in the production history of those wells. But we've tested them in areas where we have existing wells that were completed with the older techniques and styles, and we'll come in and do some of these new techniques. We've also tested these in areas where we have no wells that were completed. So we've got a subset of data that's going to be coming to us over the next several quarters that we ought to be able to help diagnose what some of the better techniques to do going forward. Now, what we can pretty well tell you is they're going to be different in each area, so there won't be any cookie cutter answer for anything. But, in general, we're looking at that 1,600 to 2,000 pound per foot sand concentrations and the more high-density near-wellbore completions.

Okay. Thanks for that, Mike. And then on the longer laterals, looking at – I guess it's slide 12, it looks like you guys are keeping the EUR per foot constant across the various lateral lengths and you guys talked about drilling some even 13,000 footers. Is that holding pretty consistent in terms of not seeing any EUR degradation as you stretch the laterals out?

I'll tell you the data we've seen so far is pretty encouraging. The one thing, when you get to real long laterals, particularly in the high productivity zones, sometimes you might be limited early-on on how much total fluid you can move. So you might not – in the first few months, you're probably not seeing quite as high of peak rates on the longer laterals, but the data that we've seen so far, both our data and other data that we traded for, seems to indicate that it's pretty close to a one-to-one relationship with lateral lengths.

Okay, great. Appreciate the detail. That's it for me. Thanks, guys.

Thanks. Good morning. Just wanted to, I guess, talk a little bit about the comment you made regarding Lower Spraberry and Andrews and Martin County being competitive with Midland. But then in response to a question around rig allocation, and I don't believe you mentioned allocating a rig to that area in 2017. Did I hear that right? And number two, can you just kind of talk through what would get you more interested in putting rigs in that area?

Yes. So what I tried to indicate was that northeast Andrews and northwest Martin County could accommodate about two rigs, because of the 10,000 to 15,000 acre spot. So it's really two there, two in Andrew and two in – one or two in Howard, one or two in Glasscock, and two or three in Midland County and one in the Delaware. So I also pointed out that we've got – it's somewhat fungible because we've got such high rate of return wells in each of those areas. The actual decision to allocate capital is a little complicated because all the wells are so equal in performance. So we're not at all scared to allocate capital in northeast Andrews and northwest Martin County. We believe that it's a really great area for us.

Okay. So it sounds like that area will get some capital in 2017 then?

Again, in terms of also, Michael, we sort of took a pause on that earlier this year when commodity prices got really low because most of that acreage is either held or only has a one-well per year commitment. So it looks like our activity was somewhat muted there. But it was really just when we got down to three rigs, thinking we were going to go to one, that we stopped development in that area because, quite honestly, we didn't have to allocate capital at that time.

Got it. That's helpful, understood. And then in the context of those five operating areas, the southern Midland didn't get a call out. I'm just curious how that's sitting in the portfolio today and kind of what's needed to keep that acreage whole?

Yeah. We've got it mostly held by production. It's down in Upton County and it's what we call our price-dependent inventory and we probably need $55, $60 a barrel at today's D&C cost to be competitive with the rest of our capital allocation. Certainly, if we got up to that eight to ten-rig cadence, that would imply a commodity price that would generate probably one rig, if not full-time, at least part-time down there in that area.

Okay. That's helpful. And then just wanted to zero in on the Wolfcamp B in Howard County. Did you look at pressure drawdown between that and A? Is there a material difference in the two intervals? And the early – the first well versus the second well, maybe talk a little bit about the comment that the second is outperforming. What's leading you to believe that this early on? Just some more commentary around that.

Yeah. I mean, if you compare the Wolfcamp A and Wolfcamp B, if you look at the IPs we reported for the Reed wells this time and for the Hodnett well the last time, there is not much difference in 30-day IP between the A and the B. But the B, pressure draws down little quicker, little bit steeper decline and that's why we think long-term the Wolfcamp A will be the better zone. And then on the question comparing the second pad to the first pad, again, it's fairly early. The rates aren't that much different, but the pressure is holding in quite a bit better on the Reed well than it did on the Hodnett well.

Okay.

Whether that's due to the high-density near-wellbore frac on the Reed well or whether it's just a geologic difference, we don't know yet. But so far – and again, it's very early. We probably have three weeks of total production on these wells. At least very early on, the Reed Wolfcamp B does appear to be outperforming the Hodnett Wolfcamp B, though.

Got it. And the last one on my end was, just going over to the Southern Delaware Basin. I believe you all have about a 50% working interest in that area, if I recall. Any thoughts on – just kind of update if you have any line of sight on potentially increasing that working interest and kind of blocking up or cleaning up some of that acreage at this stage?

Yeah, I mean there's really three things going on there. One is we're working on some acreage trades that won't increase our total net acreage, but it will increase our working interest in the wells we drill. And I'll tell you, we've been pretty encouraged by the amount of activity we've got so far and willing offset operators. And the other piece is, we continue to pick up additional acreage in that area as well, so increase our total net acreage in the area. So right now we're fairly encouraged by the success we've had on both of those fronts.

What's your current gross on that? Do you have that by chance?

I don't have that. That number would be, think of it, can say it has increased since the initial acquisition.

Okay. I'll follow-up. Actually, one more if I could squeeze it in. Just curious, you guys have in the past talked about 100,000 barrel a day capacity from the asset. As we firmed up 2017 a bit more here, I'm just wondering if you have any more, I guess, views on as to how quickly you can get to that level.

Yeah, Michael, we stretched by providing 2017 guidance as early as we did. Certainly to talk about 2018 or 2019, I think, is way premature at this point.

All right. I figured I'd give it a shot. Appreciate it.

Good effort.