Good day, ladies and gentlemen, and welcome to the Diamondback Energy and Viper Energy Partners Third Quarter 2016 Earnings Conference Call. As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Kay Svanthoff, Vice President of Strategy and Corporate Development. Sir, you may begin.
Thank you. Good morning, and welcome to Diamondback Energy and Viper Energy Partners' joint Q3 2016 conference call. During our call today, we will 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 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 will now turn the call over to Travis Stice.
Thank you, Kees. Welcome, everyone, and thank you for listening to Diamondback and Viper Energy Partners' 3rd quarter 2016 conference call. Diamondback remains optimistic on the commodity price recovery and has continued to reaccelerate the pace of activity by adding a 5th rig in October and plans to add a 6th rig in early 2017 on our recently closed Delaware Basin acquisition and could potentially add a 7th 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 multiyearorganicgrowth@ornearcashflow@currentstripprices. 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 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 and E costs. Q3 2016 cash operating costs are $9.15 per barrel, including cash G and 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 5 core areas capable of 1,000,000 barrel plus EURs. In each of these areas, we are 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 and achieve new company execution milestones. Slide 7 shows Delaware offset results. They continue to improve and we now have 4 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 2 new 10,000 foot Wolfcamp B wells in Glascott County. The target 3,905 and 3,904 Wolfcamp B wells achieved an average 30 day flowing IP rate of 14.25 BOE per day with an 85% oil cut. We also completed a second 2 well Wolfcamp B pad with 8,000 foot laterals that averaged a 30 day flowing IP rate of 10.70 BOE per day, also with an 85% oil cut. 2 of the 4 wells completed during the Q3 continue to flow naturally with all 4 Wolfcamp B wells producing similarly to our prior Wolfcamp A wells in Glasgow County. These 4 Wolfcamp B wells are tracking a normalized 7,500 foot lateral type curve of 1,000,000 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 lead Wolfcamp A achieved a 2 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 1800 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 Hoddenet wells indicate after a 4 month production history, they are tracking a 7,500 foot lateral pipe curve of over 1,000,000 BOE in the Wolfcamp A and nearly 900 MBOE each in the Lower Spraberry and Wolfcamp B. We believe this confirms 3 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 best in class Spraberry resource. In Martin and Andrews County, Lower Spraberry Wells are tracking 1,000,000 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 Q3 of 2016, we drilled 3 wells across the Northern Midland Basin with an average lateral lengths of 10,900 foot and an average of 11.5 days each from spud to total depth.
We also drilled 2 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 remained below $6,000,000 for a 10,000 foot lateral well and below $5,000,000 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 reduced our LOE by 24% to $5.37 per BOE in the Q3 of 2016 due to improved pumping practices as well as service call concessions. Illustrated another way, the 1st 9 months of 2016 versus the 1st 9 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 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 3rd quarter 2016 net income adjusted for non cash derivatives and impairment was $42,000,000 or $0.54 per diluted share. Our adjusted EBITDA for the quarter was $102,000,000 Diamondback's average realized price per BOE including hedges for the Q3 was $34.30 During the quarter, our cash G and A costs were $0.88 per BOE, while non cash G and A costs were $1.52 During the quarter, Diamondback spent approximately $75,000,000 on drilling and completion, dollars 7,000,000 on infrastructure and $9,000,000 on non operated properties. We spent an additional $701,000,000 on acquisitions during the Q3. This included approximately $126,000,000 at the Viper level.
In connection with our fall redetermination, Diamondback's lenders approved a $1,000,000,000 borrowing base under its credit facility, up 43% from $700,000,000 previously. However, we again elected to limit the lender's aggregate commitment to $500,000,000 With over $160,000,000 in cash and an undrawn borrowing base with $500,000,000 in capacity, we have ample liquidity to fund our upcoming activity. As shown on Slide 17, Diamondback ended the Q3 of 2016 with a net debt to trailing 12 months adjusted EBITDA ratio of 0.9x. 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 $350,000,000 to $425,000,000 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% atornearbreakevencashflow. I'll now turn to Viper Energy Partners, which announced on October 27, a cash distribution of $20.07 per unit for the 3rd quarter, up 10% from the Q2 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 Q3 of 2016, Viper had $54,500,000 drawn on its revolving credit facility. In October, Viper's lenders approved a $275,000,000 borrowing base, up 57% from $175,000,000 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 in 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 remained 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 Viper and are excited to begin development in the Southern Delaware Basin. Operator, please open the line up for questions.
Thank you. And our first question comes from the line of Neal Dingmann with SunTrust. Your line is
now open.
Good morning, Travis, guys and Tracy, nice quarter. Say, Travis, two things here. First, you mentioned about maybe perhaps bringing a 7th rig next year. Could you talk maybe just in broad terms, Travis, how you would attack? I mean, now that you mentioned the great results in Glasscock, Howard as well as even in Andrews, you had the 6 to 7 rigs running, how would you allocate those including the Delaware area?
Sure. So if we got to a 7 rig cadence, most likely in the back half of next year, you'd have 6 rigs working in the Midland Basin and you'd have 1 rig working in the Delaware. And those 6 rigs will be allocated between likely 1, 2 in Howard County, 1, 2 in Glasscock and 1, 2 or 3 in Midland County and actually 2 or 3 in Midland County. And so the rigs are a little fungible. And one of the reasons that we pointed out that we've got 5 core areas that are capable of little rail type EURs is because we believe we've got lots of opportunities to deliver really nice returns to our investors.
And then Travis, and Howard and some of well, 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. Is your drilling these, are you going to I know kind of looking at the Delaware, you're talking about doing mostly just Wolfcamp A. If you now when you're targeting the Midland next year, will you do sort of multi stack or how do you what do you think the focus is going to be when you look at Howard, specifically in Howard and Glasscock?
Yes. So Neil, that's a good question. 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 AB in Lower Spraberry, still kind of up in the air until we get a little bit more established in season 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 Northwest Andrews and Northwest Martin and Northeast Andrews is going to be the Lower Spraberry. So we've really got 2 zones that are clearly best in class, and we believe that the D and C and E cost that we're doing right now is probably at an all time low.
And so we've got really nice 1,000,000 barrel wells that we're bringing online at an all time low DC and E cost, and we think that's going to drive our production growth next year to as well as staying within cash flow.
Got it. And 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 2 by ones 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, down, how you think about that including the hedges?
Sure. Neal, we've always talked in times past
that we
believe hedges is financial engineering tools, and we typically disassociate those with real time operation decisions because you're putting hedges on for current calendar year and you're producing these wells for another 50 years. That being said, though, we believe these creative 2 by 1 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 November, December this year and through the first half of next year. That being said though, our balance sheet is, 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 is recovering, well, yes, 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.
And our next question comes from the line of John Nelson with Goldman Sachs. Your line is now open.
Good morning and congrats on another quarter of strong execution.
Thanks, John.
On Slide 7, I think you guys incrementally showed a peer result in the 2nd Bone Spring over in the Delaware Basin. I know you included some Delaware I'm sorry, some 2nd Bone Spring credit in your locations when you announced the acquisition. But can you just speak to is pure 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 targets what horizons that will target early on?
Sure. When we bought that acquisition, we underpinned it really with 2 zones, the Wolfcamp A and the Wolfcamp A, the Third Bone Springs and the Wolfcamp B. So those are the zones that we felt like were derisked. We recognize that there's upside in the 2nd Bone Springs. And I'm going to let Russell address what we found out about the 2nd Bone Springs since the acquisition time.
Specifically to your question on where that rig is going to get allocated, we'll be drilling probably 5 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 pads, and we'll be doing Bs 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 2nd Bone Spring question?
Yes. I mean, obviously, I mean, we're encouraged by the results we've seen out of the 2nd Bone. There's possibly a limited number of tests based on the analysis we did before the acquisitions. 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 3rd Bone. And one of the early wells we drill there, will core the intervals and based on the results of that core and early results, we'll make our decisions 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 some detail on the presentation about how wells are outperforming type curves. As we go into 4Q, should we be expecting any type of type of type 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?
Yes. John, we've historically been very conservative in our type curve communication. We all like to keep 2 sets of books, kind of a management expectation book and a Ryder Scott book. So we always air on Ryder Scott books. The numbers that you hear us quote are Ryder Scott reserve numbers.
We do have reviews scheduled between now and 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, probably sometime in the Q1.
And our next question comes from the line of Michael Glick with JPMorgan. Your line is now open.
Good morning. Just looking at your core operating areas, your spacing assumptions do appear conservative relative to your peers. Could you talk a bit about your thought process on down spacing and plans to test tighter spacing over the near and intermediate term?
Yes. 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 downspacing. 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 the 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 industries are 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.
Yes. I mean, we've done down spacing tests in the Lower Spraberry and other zones as well. It's still early. We'll sit down with Ryder Scott particularly in the Lower Spraberry where we've just now we're 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 3 well pads or 2 well pads where the early results were very encouraging. But we think you really have to look at it in a full type of 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 them 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 5 core operating areas, could you speak to about how many rigs you think that could 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 the 2 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 we kind of that's kind of how we set it up.
And if you look across our asset base, you can see each of those core areas. They all average somewhere between 10000,000 and 15,000 acres. So notionally, inside those circles, you can run 2 rigs in each of those areas. Oh, and then a question on people, yes. We're in pretty good shape.
We always are looking to add a few key contributors. And 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. And if we do ramp up, you'll probably see a small increase in personnel. I think we're at about 160 employees right now, including field operations.
All right. Thank you very much.
And our next question comes from the line of Drew Venker with Morgan Stanley. Your line is now open.
Good morning, everyone. I was hoping, Travis, on a follow-up to Neil's question on the rig ramp. Could you talk about what your plans are thinking is on Delaware longer term, so beyond 2017? How much activity you'd expect in the other infrastructure build out and other considerations you'd have on further increasing activity in the Delaware?
Sure. I'm going to I'll answer your question on rig ramp, then I'm going to turn 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 1 rig per year for the next 4 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 on my previous commentary of kind of 2 rigs for 10,000 acres, we've got roughly 20,000 acres there.
So we could get to 4 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 1 to 4 rig ramp over the next 4 years. Certainly, with results, commodity price, etcetera, we can look to accelerate that. I'll let Kees give us a thumbnail sketch of where we are in infrastructure out there.
Yes. On the Delaware, when we bought the transaction, it came with 25,000 barrels a day of saltwater disposal capacity. So I think we're good there for the foreseeable future. Freshwater, we're looking to build our own freshwater infrastructure throughout the majority of the leasehold. And we're currently in discussions on the midstream side, both oil and gas with 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 is it building out?
Yes, 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 2 ago. Is that consistent with your perspective? And if it is, can you identify any is there any single driver that's responsible for the bulk of that improvement?
Yes. I mean, we're always trying to optimize our results either through both landing zone and stimulation. We've talked 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. Some of the early results are fairly encouraging.
And I think if you looked at our current stimulations on average, we're probably in the 1600 to 1800 pound per foot range during the high density and near well 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 will be based on the returns we're getting for those incremental dollars that we're spending and we'll continue to monitor the results make changes going forward as appropriate.
Thanks for the color.
Yes. 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 dollars.
So when you hear us talk about results from these different techniques that we're trying, we always underpin it, 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.
And our next question comes from the line of Mike Kelly with Seaport Global. Your line is now open.
Thanks. Good morning. Travis, there's been some concern lately from investors here you and the other Permian High Flyers are growing to activities 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 do some basis hedging today that might protect you?
Have you thought of that? Thank you.
Yes. I'll let Mike, I'm going to let Kees answer that question.
Yes. Hey Mike, we released today that we have 24,000 barrels a day of basis protection for next year in 2017 and 10,000 a day placed for 2018. I think we're looking at it 2 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 2, 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 just the inter 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.
Travis, going back to Lower Spraberry
and Howard, and 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. It does look like the profile is different versus what you're bringing on in Midland. And just 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.
Yes. 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 is 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 4 months of production history. So when Russell looks at that well, he's not just making 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?
Yes. I'll just say, I mean,
for the most part, the profile that we're seeing is fairly typical of the majority of the Lower Spraberry 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 microseismic survey that we completed on that read through 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 stimulation 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 do some things to get some higher initial rates. But again, as we said, we're pleased with what our projected EURs are. Again, it is fairly early time, but we've got offset operator data that's probably got a year or more production history in some cases that gives us some pretty good confidence that the EURs are going to be getting.
Okay, great guys. Thank you.
And our next question comes from the line of Pierce Hammond with Simmons. Your line is now open.
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?
Yes. I can just tell you, Pierce, 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 intellectually 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're 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, it's we just don't see a whole lot of reason on the pressure pumping side for cost to go up in 2017 if we're going to be range bound in that 45 dollars to $50 barrel world. Rigs, we've got plenty of drilling rigs. No worries there for the foreseeable future. And those are really the 2 big spend items and we monitor those 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? There's still plenty of deals out there. Do you think valuations maybe need to come down a little bit?
And even just some color between the Delaware and the Midland, if you could provide it?
Yes. Pierce, we've got a pretty consistent record. I'm 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's still on the Midland Basin side, we see smaller sized trades that are occurring that, 1, 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 have 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's just a whole bunch of opportunities there in the Delaware. And I don't know if there's 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, Pierce. Thank you.
And our next question comes from the line of Jeff Grampp with Northland Capital Markets. Your line is now open.
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 data set internally with Diamondback Wells as far as kind of the well history and the aggregate data set and kind of what you're all obviously the encouraging results and how are some of the other areas. But just kind of wanted to get a greater sense of what the ultimate data set is internally within Diamondback for those types of wells?
Well, Jeff, this is Mike. We've been doing testing since we've started fracing 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 with 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 16,000 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, at Slide 12, it looks like you guys are kind of 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'd say the data that 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 1st few months, you're probably not seeing quite as high a peak rates on the longer laterals. But the data that we've seen so far, both our data and other data that we've traded for, seems to indicate that it's pretty close to a one to one relationship with Lateral Length.
Okay, great. Appreciate the detail. That's it for me. Thanks guys.
And our next question comes from the line of Michael Hall with Heikkinen Energy Advisors. Your line is now open.
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, I don't believe you mentioned allocating a rig to that area in 2017. I guess number 1, was that did I hear that right?
And number 2, can you just kind of talk through what would get you more interested in putting rigs in that area?
Yes. So what I've tried to indicate was that Northeast Andrews and Northwest Martin County could accommodate about 2 rigs because it's that 10000 to 15000 acre spot. And so it's really 2 there, and 12 in Howard, 12 in Glasscock and 23 in Midland County and 1 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 does sound like that area will get some capital in 2017 then? Yes.
And again, in terms of also, Michael, we sort of took a pause on that earlier this year when commodity prices got real low because most of that acreage is either held or only has a 1 well per year commitment. So it looks like our activity was somewhat muted there, but it was really just when we got down to 3 rigs thinking we were going to go to 1 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 5 operating areas, the Southern Midland didn't get a call. I'm just curious how that's sitting in the portfolio today and kind of what's needed to keep that acreage whole?
Yes. We've got it mostly held by production that'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 and C cost to be competitive with the rest of our capital allocation. Certainly, if we got up to that 8 to 10 rig cadence, that would imply a commodity price that would probably generate at least 1 probably 1 rig, but if not full time, at least part time down there in that area.
Okay. That's helpful. And then just wanted to zero in a little bit on the Wolfcamp B in Howard County. Are you like as you look at pressure drawdown between that and the A, is there 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.
Yes. 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 high net wells the last time. There's not much difference in 30 day IP between the A and the B. But the B, pressure draws down a little quicker, a little bit steeper decline. And that's why we think long term, the Wolfcamp A will be the better zone.
And then then on your question comparing the 2nd pad to the 1st pad, again, it's fairly early. I mean, 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 Hotnet well. 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 3 weeks of total production on these wells. At least very early on, in terms of the Reed, Wolfcamp B does appear to be outperforming the hog at Wolfcamp B.
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? I mean, there's really 2 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 hopefully, we've been pretty encouraged by the amount of activity we've got so far and willing to offset operators. And the other piece is we continue to pick up additional acreage in that area as well. So to increase our total net acreage in the area.
So right now, we're I'd say we're fairly encouraged by the success we've had on both of those fronts.
What's your current gross in that? Do you have that by chance?
I don't have that number with me.
Okay. I have a follow-up.
Can't say it has increased since the initial acquisition.
Okay. I'll follow-up. Actually one more if I could sneak 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?
Yes.
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. Figured I'd give it a shot. Appreciate it. Solid quarter.
It's a
good effort.
And our next question comes from the line of Gail Nicholson with KLR Group. Your line is now open.
Good morning. Looking at the slide deck, you have about 17% of your inventories around 5,000 foot laterals. What percentage of that inventory do you think you can increase the lateral length via acreage swap? And then what percentage of that inventory do you think is just going to always be kind of a shorter lateral?
I think it's probably about at least 30% of those would probably end up being shorter laterals. And a lot of those are, I will say, are Spanish Trail, Lower Spraberry, where just due to the acreage configuration and some of the surface issues in the area, we'll probably call it be limited due to 5,000 foot laterals. A lot of the rest of it is acreage that we think will eventually be able to walk up either through drilling joint wells with other operators or making acreage trades. But we've still got those in our inventories short laterals because we haven't actually incented those deals yet, but we continue to work on.
Okay, great. And then just turning over to Glasscock County, of the 4 wells that were turned online, 2 of those are flowing naturally. And actually, they're each flowing on separate pads flowing naturally with the other one on ESP. Can you talk about, what you're seeing over there? Did you complete those differently?
Were they in a different landing zone? And then do you think Glasscock in general might have more wells flow naturally versus the rest of your Midland Basin acreage?
Yes. I think Glasscock, it is a
little higher GOR area. So I mean they most of the wells do flow naturally for some period of time, varies from well to well, maybe it's a month, maybe as long as 3 or 4 or 5 months depending on the well. There were some slight differences in landing zones on those pads. And so that may be contributing to the reason that one flows longer than the other. But I'll say when you actually look at the data between the two zones, I mean, there's very slight differences.
The difference in flowing pressure probably doesn't differ by more than 100 PSI between the wells. So it's not significant. And you just have one surface production that's it can cause a well to stop flowing. And at that point, we'll go ahead and run the ESP. So probably not as much differences as you might be thinking from just looking at the data at a high level.
Okay, great. Thank you. And our next question comes from the line of Jason Wangler with Wunderlich. Your line is now open.
Hi. Travis, just curious, you talked about service pricing and things. How is it looking as far as just equipment availability? You kind of mentioned, obviously, they're not really replacing things right now. And obviously, activity for you guys and everybody else is increasing.
How are you seeing that kind of side of it looking as you guys continue to kind of pick up more and more over the next couple of
years? Hey, Jason, this is Mike Hollis. I'll take this one for you. Kind of as we've mentioned in the past, as long as the Permian Basin is pretty much the only bellwether right now adding any activity short of the scoot and stack area, Availability of iron typically isn't a problem right now. Very short term, if you called something out tomorrow, maybe a difficult thing.
But if you've got a week or 2, getting iron in people usually isn't an issue. We see that coming more later in the second half of twenty seventeen or in twenty eighteen when some of the other basins pick back up and we're all competing for the same services at that point. But for right now, service equipment and people are easily accessible.
Yes. Thanks, Mike. And I mean, the old rule of
thumb is they all everything has wheels on it.
So is it mostly bringing things into the Permian, as said, being the bellwether from other areas? Because I had assumed that there's not a lot of new equipment, so it's mostly bringing in people and equipment from the basins
that were more active historically. Is that fair?
That's correct. Yes, sir. We still see trucks coming into the basin every day.
Okay, great. Thank you guys. I'll turn it back. Yes.
And our next question comes from the line of Richard Tullis with Capital One Securities. Your line is now open.
Thanks. Good morning, everyone. Just a couple of quick questions, Travis. Fang has done a real good job lowering cash OpEx over the past year or 2, or even going beyond that. What's the outlook for 2017 given startup of drilling in Southern Delaware Basin?
Any capacity to lower further at that point?
We gave did we give guidance for 2017 OpEx? So we haven't done it yet. But I think LOEs is one of those things that we always continue to push on regardless of what commodity price is. And I think Mike did a good job of laying out in his prepared remarks that his organization is working on not only the absolute dollars in the numerator, but we're also adding volumes in the denominator, which makes that ratio look really good. The LOE costs, Richard, are typically a little bit more sticky than what you see on the service costs, DC and E side.
Your large spend areas, electricity, chemicals, water disposal, manpower, those type of things that are at the top of your LOS statement usually don't have much movement to it. So we believe that we're sort of it might move down slightly, but we're sort of at that asymptotic portion of that cost reduction. And we'll see. But our corporate culture is to always push on LOE until we can produce these wells for free. So we're always going to try to push on that
And then if you guys decided to add that 7th rig next year, where would that rig be placed? Sorry if I missed that, if you already went over it.
No worries. It will be in the Midland Basin side and it kind of follows some of that 2 per 10,000 acre metrics that I laid out. So you'd have if you were to 7 rig cages, you'd have 6 in the Midland Basin and 1 in the Delaware.
Okay. And then just lastly, obviously great production growth in the Q3, with 32% quarter over quarter growth. What was the exit rate for the quarter, if you're able to say that, Travis?
I don't think we released that information. Exit rates for the quarter, Richard, with as much activity as we've got going on, the reason we don't provide annual guidance is because I mean quarterly guidance is because in any given quarter, if we've got a frac crew in one of our high producing areas, we could be watered we could have watered out or shut in 5,000,000 to 8000 barrels a day of production shut in. So I don't pay much attention to quarterly exits. It's probably reasonable to ask me what to exit the year at when we get there. But quarterly exit, I quite honestly couldn't even tell you.
Yes, Richard, I mean Page 5 of our deck that we released will give you a pretty good idea without giving you the exact number.
All right, good enough. I appreciate it. Thank you.
And our next question comes from the line of Sam Burwell with Canaccord. Your line is now open.
Good morning, guys. I wanted to go back to the Spraberry and Andrews and Martin. Looking at Slide 11, you laid out the production history of the wells. Most of them look to be kind of older vintage, like at least a year online. So I was wondering if it was safe to assume that most, if not all of these completed with an older, smaller frac design and when you guys go back up there, probably with a newer larger one, do you expect a meaningful uplift from what we see here?
Sam, you might have heard me talk about this before, but when this executive team came together, we brought with us multiple decades of developing unconventional resources horizontally from the Montana, Bakken to North Dakota middle member to the Barnett Shale, the Marcellus and Utica. And what we brought with us was a bench strength of completion expertise on horizontal wells. So the first well that we fracked in 2012 was with 1500 pounds of sand for slickwater at 100 barrels a minute. And we've only made slight tweaks to that, as Mike outlined, over the time. So when you ask me about what we're going to do with these new completions in Northeast Andrews and Northwest Martin.
The most likely thing we'll do is modify them to the high density near wellbore. But you're not going to see you just don't see we started with whatever the buzzword is, Gen 5 or Gen 3, that's really where we started in 2012.
Okay. Got it. Appreciate the color. And then just one quick follow-up on in this area. Do you guys plan to test any Middle Spraberry or Joe Mill wells?
It looks like just eyeballing this, all these were lower spray barriers.
Yes. I think there's a reasonable chance we'd do a middle spray berry test in 2017. If you I know there's a lot of offset operators or quite a few offset operators that have drilled Middle Spraberry in the area. And several of those wells are probably within a mile of our acreage, and the results have been very encouraging. So we're pretty certain we have Middle Spraberry potential on our acreage.
Again, the IPs on the Middle Spraberry haven't been as good as the Lower Spraberry, but the EURs still look good. So we'll probably test it at some point. But with all the offset activity we've got in the area, we feel like the zone's proved up on our acreage. And so there's not a real need for us to step out and test it anytime soon where we're seeing the really good results from the lower spreader.
And our next question comes from the line of Dan McSpirit with BMO Capital Markets. Your line is now open.
Thank you. Folks, good morning and thank you for taking my questions. Just a quick follow-up on the enhanced completions. Has the Efficient Frontier been reached yet in the Permian Basin with say £2,000 per foot or greater sand loadings be tested? And how do those sand loadings differ by zone or by area, meaning is more or less needed in any one zone because of the unique rock characteristics involved?
Dan, this is Mike. I'll take that. The answer to every one of those questions is basically yes.
We
don't think that we found the efficient frontier just yet. You've seen some folks really push the edge and have pulled back in that 18,000 to 2,000 seems to be about the right number. Everyone that's gone a little farther have come back just from look once they start looking at the rate of return driven economics of what they're spending and what they're getting. Now each one of the zones will be different and each one of the counties will be slightly different. So to give a blanket answer as to what it is, it's really difficult to do that right now.
But as we go forward, we are moving more towards those high density near wellbore fracs, diversions where appropriate, diversion agents.
One of
the things we're also seeing is we're migrating to more of a stack and staggered approach to a lot of these zones to give ourselves a little bit more distance within the same number of wells per section. We get a little bit more physical distance away from the wellbores. And as we do these high density near wellbore fracs, we're trying to condense the amount of rock that we're touching. So over time, yes, we have gone to a higher sand loading, but we've also gone to lower rates at which we're pumping. So we're not getting out and touching as much rock and we're trying to get a higher recovery factory recovery factor, sorry about that, from the rock that we are touching near wellbore.
So a lot of knobs are being turned right now. But to say that we've hit that final frontier here in the Midland Basin is hard to say. We're a little bit farther along than over in the Delaware where you're starting. You're still seeing large differences from the changes that these folks are making. Again, they also started from a much different starting point with very low sand concentrations, more hybrid fracs and gel loaded fracs.
So you're seeing a lot of changes in the Delaware more so than the Midland side. Got it. Helpful. Thank you and have a great day.
You too. Thanks.
Thank you, Dan.
And our next question comes from the line of Tim Rezvan with Mizuho Securities. Your line is now open.
Hi, good morning folks. Most of my questions have been answered. I had a quick one. I guess we haven't talked about Viper much. Your debt was relatively unchanged, looks like in the Q3, but you increased your borrowing base by $100,000,000 Should we read into that?
I mean,
I guess if you could repeat your
kind of broad outlook, you talked about M and A on kind of what, if anything you've seen on the mineral side?
Hey, Tim, this is Case here. Yes, we've seen a lot more activity on the M and A front for Viper kind of starting at the end of Q2 into Q3 with the $126,000,000 of acquisitions we did in the quarter, most of that funded via the equity deal we did in July. Borrowing base was raised and I think we continue to use that borrowing base as a way to fund acquisitions, bundle up a few and then go out to the market. I think we want to keep the same low leverage mentality of Viper we've kept at Diamondback and simply do deals that are accretive to that distribution.
Okay. So it's safe
to say you're seeing maybe the bid and ask maybe starting to converge a little more?
Correct. Correct. I think we've done $300,000,000 of total deals in 2 years and 126 of them were in 1 quarter. So I think that trend should continue based on what we're seeing.
Okay. That's all I had. Thank you.
I'm showing no further questions at this time. I would now like to turn the call back over to Mr. Travis Vice for any closing remarks.
Thanks again to everyone participating in today's call. If you have any questions, please contact us using the contact information provided.