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, Kaes Van't Hof, 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 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 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, Kaes. Welcome everyone, and thank you for listening to Diamondback and Viper Energy Partners's third quarter 2016 conference call. Diamondback remains optimistic on a commodity price recovery and has continued to re-accelerate the pace of activity by adding a fifth rig in October, and plans to add a sixth rig in early 2017 on a 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 41,000-42,000 barrels a day from 38,000-40,000 barrels a day, while keeping capital spend guidance unchanged. We have also introduced our 2017 production guidance of 52,000-58,000 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-$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 D&C 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 five, Diamondback has a track record of accretive acquisitions and continues to evaluate deals in the Permian Basin. As shown on slide six, we have amassed a robust inventory with five core areas capable of 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 and achieve new company execution milestones. Slide seven 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 a new Southern Delaware leasehold at the beginning of next year. Slide eight shows two new 10,000-foot Wolfcamp B wells in Glasscock County. The target 3905 and 3904 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 nine, 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. 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 appears 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-foot 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 best-in-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 and an average of 11 and a half 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 drilled 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 costs 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've 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-$6 per BOE, compared to $5.50-$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, nanosurfactants, 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. 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-$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 break-even cash flow.
I'll now turn to Viper Energy Partners, which announced on October 27th 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 7th. 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 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. Ladies and gentlemen, if you would like to ask a question at this time, please press the star and then the number 1 key on your touch-tone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. Our first question comes from the line of Neal Dingmann with SunTrust. Your line is now open.
Morning, Travis, guys. Tracy, nice quarter. Travis, two things here. First, mentioned about maybe perhaps bringing a seventh rig next year. Could you talk maybe just in broad terms, Travis, how you would attack? That you've mentioned the great results in Glasscock, Howard, as well as even in Andrews, if you had the six to seven rigs running, how would you allocate those, including the Delaware area?
Sure. 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. Those six rigs would be allocated between likely one, two in Howard County, one, two in Glasscock, and one, two or three in Midland County. Actually two or three in Midland County. 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 million-barrel type EURs is because we believe we've got lots of opportunities to deliver really nice returns to our investors.
Travis, in Howard and some of the Well, not just Howard, but many of these areas you talk about the Wolfcamp A, B, Lower Spraberry, a number of successful intervals. Is your drilling these? I know looking at the Delaware, you were 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 what do you think the focus is going to be when you look at Howard, specifically in Howard and Glasscock?
Neal, 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. Now whether we drill those all in the A or in A, B, in Lower Spraberry, it's still up in the air until we get a little bit more established in season production on our tests 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. 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.
We've really got two zones that are clearly best in class, and we believe that the DC&E cost that we're doing right now is probably at an all-time low. We've got really nice 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. 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. When you see sort of growth for next year, is it just based on return driven? I guess the question would be if you can add more hedges, like these others, these two-by-ones and lock in some of that, would that cause you to perhaps remain more active even if prices drop? 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 is financial engineering tools, we typically disassociate those with real-time operation decisions because you're putting hedges on for a current calendar year, you're producing these wells for another 50 years. That being said, though, we believe these creative two-by-one collars that we put in place give us some protection on the downside 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.
We've got the ability to continue our rate of return and NPV-focused strategy on allocating capital. We don't mind accelerating activity into a recovery. If we continue to see things that indicate commodity prices recovering and our industry is recovering, 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 details, Travis.
Thank you, Neal.
Our next question comes from the line of John Nelson with Goldman Sachs. Your line is now open.
Good morning. Congrats on another quarter of strong execution.
Thanks, John.
On slide seven, 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. 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? 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, the Third Bone Spring, and the Wolfcamp B. Those are the zones that we felt like were de-risked. We recognize that there's upside in the Second Bone Spring. I'm going to let Russell address what we found out about the Second Bone Spring 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 pads, and we'll be doing Bs and Third Bone Spring 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?
Obviously, we're encouraged by the results we've 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. As Travis was saying, our focus will really be on the Wolfcamp and the Third Bone. 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. 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. I guess just as my second question, you provide some detail in the presentation about how wells are outperforming type curves. As we go into 4Q, should we be expecting any type of type curve update alongside the reserve update at year-end, or do you think you'll continue to gather data before potentially making any changes there?
John, we've historically been very conservative in our type curve communication. We like to keep two sets of books, kind of a management expectation book and a Ryder Scott book. 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 end of the year with Ryder Scott, and I expect Russell and his team to sit down with those guys, and we'll see. We'll communicate whatever those results are when we get them wrapped up. It'll probably be sometime in the first quarter.
Perfect. I'll let somebody else hop on. Congrats again.
Thanks, John.
Our next question comes from the line of Michael Glick with J.P. Morgan. Your line is now open.
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?
Yeah. Just in general, Michael, Russ will 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. If our peers in the 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's 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 sit down with Ryder Scott, particularly in the Lower Spraberry, where just now we're actually going to 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. We think you really have to look at it in a whole section development mode to see what the true results are. 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.
Based on our analysis and theirs as well, we'll report what we're seeing.
Got it. Then just with 5 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?
In general, this is just 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. 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. That's how we set it up. If you look across our asset base, you can see each of those core areas. They all average somewhere between 10 and 15,000 acres. Notionally, inside those circles, you can run two rigs, in each of those areas. 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.
We're always looking for the best and the brightest to come join our team. 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.
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 Stice, on a follow-up to that, Neal Dingmann's question on the rig ramp. Could you talk about what your plans are, your thinking is on the Delaware longer term, so beyond 2017? How much activity you'd expect, any other infrastructure build out, or other considerations you'd have on further increasing activity in the Delaware.
Sure. I'll answer your question on rig ramp, and then I'm going to turn it to Kaes Van't Hof and let him talk about the infrastructure. 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. One of the levers that we can control that drives differential value to our investors is by accelerating that. If you go on my previous commentary of two rigs per 10,000 acres, we've got roughly 20,000 acres there. We could get to four rigs sooner pretty efficiently. We just need to get out there and start drilling. 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 results, commodity price, et cetera, we could look to accelerate that. I'll let Kaes Van't Hof give us a thumbnail sketch of where we are on infrastructure out there.
Yeah, on the Delaware, when we bought the transaction, it came with 25,000 barrels a day of saltwater disposal capacity. 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? 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 private equity-backed guys that are already out there.
Okay. On the well performance, it seems to be improving pretty markedly from just a quarter or two ago. Is that consistent with your perspective? If it is, can you identify, is there any single driver that's responsible for the bulk of that improvement?
Yeah. We're always trying to optimize our results, either through both landing zone and stimulation. Mike talked about that we've got a lot of different stimulation tests that we've done. Most of those are fairly early in the results. Some of the early results are fairly encouraging, I think if you looked at our current stimulations, on average, we're probably in the 16,000-18,000 pound per foot range, doing the high density near wellbore fracs. With the data we've got so far, as I said, we think those look encouraging, we're continuing with those. As we've mentioned, it'll be based on the returns we're getting for those incremental dollars that we're spending. 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. 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. 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. We hope the commentary for the industry navigates that way as well, too. Just wanted to add that, but thanks for your questions, Drew.
Thanks.
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 that you and the other kind of Permian high flyers are growing activities back to the point here where you're going to ultimately fill up trunkline capacity coming out of the Permian. I know you have some opinions on that, so just was hoping to get some color there and 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.
Yes. 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, in 2017, and 10,000 a day placed 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. We're active, and we're looking at it.
Okay. Do you have an idea what ballpark the market is for basis in 2018 right now?
It's a thinner market.
A barrel or so a month?
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. Travis, going back to the Lower Spraberry in Howard, I'm just flipping through slides, I guess this is slide nine and 10 here, 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. 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 just the early performance. Thanks.
Yeah, I'll let Russell answer it specifically. In general terms, 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. The decline rate is what really has surprised us. It's much, much shallower. We've got now, as we pointed out in our prepared remarks, we've now got over four months of production history.
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. Russell, do you want to add anything to that?
Yeah, I'll just say, for the most part, the profile that we're seeing is fairly typical of the majority of the Lower Spraberry wells in Howard County. 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, we're continuing to try some things to optimize those early time production rates. We had a microseismic survey that we completed on that Reed well pad. In the next couple of weeks, we'll be getting all that data in, we'll look to see what occurred during the stimulation, we'll make adjustments, potentially to both the landing zone and the stimulation.
We're fairly optimistic at this point that we can do some things to get some higher initial rates. Again, as we said, we're pleased with what our projected EURs are. Again, it is fairly early time, 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.
Our next question comes from the line of Pearce Hammond with Simmons. Your line is now open.
Good morning, thanks for taking my questions. My first question pertains to service cost. Travis, just curious what you're seeing right now in the way of any kind of service cost inflation currently, 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'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. We need them there to be able to answer our call when activity levels do ramp up materially. With that being said, 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-$50 a barrel world.
Rigs, we've got plenty of drilling rigs. No worries there for the foreseeable future. Those are really the two big spend items. We monitor those closely.
Thank you. 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? Even just some color between the Delaware and the Midland, if you could provide it.
Yeah, Pearce, 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. On the Midland Basin side, we see smaller sized trades that are occurring that, one, are allowing us to block up and drill longer laterals, whether they're outright acquisitions or swaps. 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, I don't know if there's buyer fatigue or not yet in the Delaware. 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. They're all looking for some form of a liquidity event for their investors. 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, congrats on a solid quarter.
You bet, Pearce. Thank you.
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 talked about. Can you give us a sense for what kind of a data set is internally with Diamondback wells as far as the well history and the aggregate data set and obviously the encouraging results in Howard and some of the other areas? Just 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 fracking wells out here in 2012 in these horizontals. It's a pretty extensive test group, and we've changed a lot of things over time. The most recent high density near well bore 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. 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.
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. What we can pretty well tell you is they're going to be different in each area, there won't be any cookie cutter answer for anything. In general, we're looking at that [16-2,000] pounds per foot sand concentrations and the more high density near well bore completions.
Okay. Thanks for that, Mike. On the longer laterals, looking at 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'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. You might not, in the first few months, you're probably not seeing quite as high a peak rates on the longer laterals. 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 length.
Okay, great. Appreciate the detail. That's it for me. Thanks, guys.
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 talk a little bit about the comment you made regarding Lower Spraberry in Andrews and Martin County being competitive with Midland. 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 one, did I hear that right? Number two, can you just talk through what would get you more interested in putting rigs in that area?
Yeah. What I tried to indicate was that Northeast Andrews and Northwest Martin County could accommodate about two rigs, because it's that 10,000 to 15,000 acre spot. It's really two there, one, two in Howard, one, two in Glasscock, and two, three in Midland County, and one in the Delaware. I also pointed out that 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. 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. It does sound like that area will get some capital in 2017 then. Fair to say.
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 one well per year commitment. 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. 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 what's needed to keep that acreage whole.
Yeah. We've got it mostly held by production that's down in Upton County. It's what we call our price-dependent inventory.
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 10 rig cadence, that would imply a commodity price that would probably generate probably one rig, if not full-time, at least part-time down there in that area.
Okay. Helpful. Just wanted to zero in a little bit on the Wolfcamp B in Howard County. As you look at pressure drawdown between that and the Wolfcamp A, is there a material difference in the two intervals? 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. 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 wells the last time, there's not much difference in 30-day IP between the Wolfcamp A and the Wolfcamp B. The Wolfcamp B, pressure draws down a little quicker and a little bit steeper decline, and that's why we think, long-term, the Wolfcamp A will be the better zone. On your question comparing the second pad to the first pad, again, it's fairly early. The rates aren't that much different, 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 frack on the Reed well or whether it's just a geologic difference, we don't know yet. So far, and again, it's very early, we probably have three weeks of total production on these wells. At least very early on, I'd say the Reed Wolfcamp B does appear to be outperforming the Hodnett Wolfcamp B well.
Got it. 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 update if you have any line of sight on potentially increasing that working interest and blocking up or cleaning up some of that acreage at this stage?
Yeah. 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. I'll tell you, we've been pretty encouraged by the amount of activity we've got so far and willing offset operators. The other piece is we continue to pick up additional acreage in that area as well. To increase our total net acreage in the area. Right now, I'd say we're fairly encouraged by the success we've had on both of those fronts.
What's your current gross on net? Do you have that by chance?
I don't have that number with me.
I can follow up.
I can say it has increased since the initial acquisition.
Okay. I'll follow up. Actually, one more if I could squeak it in. I'm 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. Figured I'd give it a shot. Appreciate it. Talk later.
It's a good effort.
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, about 17% of your inventory is around 5,000-foot laterals. What percentage of that inventory do you think you can increase the lateral length via acreage swap? 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. 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 always be limited to 5,000-foot laterals. A lot of the rest of it is acreage that we think we'll eventually be able to block up, either through drilling joint wells with other operators or making acreage trades. We've still got those in our inventory as short laterals because we haven't actually inked any of those deals yet, but we continue to work on them.
Okay, great. Just turning over to Glasscock County, of the 4 wells that were turned online, 2 of those are flowing naturally. 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? Do you think Glasscock, in general, might have more wells flow naturally versus the rest of your Midland Basin acreage?
Yeah, I think Glasscock, it is a little higher GOR area. 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. That may be contributing to the reason that one flowed longer than the other. I'll tell you, when you actually look at the data between the 2 zones, there's very slight differences. The difference in flowing pressure probably doesn't differ by more than 100 psi between the wells. It's not significant. You just have one surface production upset can cause a well to stop flowing, and at that point, we'll go ahead and run the ESP.
Probably not as much difference as you might be thinking from just looking at the data at a high level.
Okay, great. Thank you.
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 mentioned, obviously, they are not really replacing things right now, and obviously activity for you guys and everybody else is increasing. How are you seeing that side of it looking as you guys continue to pick up more and more over the next couple of years?
Hey, Jason, this is Mike Hollis. I will take this one for you. As we have mentioned in the past, as long as the Permian Basin is pretty much the only bellwether right now, adding any activity short of the Scoop and Stack area. Availability of iron typically isn't a problem right now. Very short term, if you called something out tomorrow, it may be a difficult thing. If you have got a week or two, getting iron and people usually isn't an issue. We see that coming more later in the second half of 2017 or into 2018, when some of the other basins pick back up, and we are all competing for the same services at that point. For right now, service equipment and people are easily accessible.
Great. Yeah. Thanks, Mike. The old rule of thumb is everything has wheels on it. Is it mostly bringing things into the Permian, as you said, being the bellwether from other areas? I would assume that there is not a lot of new equipment, so it is 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, sir.
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 quick questions, Travis. FANG's done a real good job lowering cash OpEx over the past year or two, 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?
Did we give guidance for 2017 OpEx? We haven't done it yet. I think LOE is one of those things that we always continue to push on, regardless of what commodity price is. 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 those service costs, DC&E side. Your large spend areas, electricity, chemicals, water disposal, manpower, those type of things that are at the top of your LOE statement usually don't have much movement to it.
We believe that it might move down slightly, but we're sort of at that asymptotic portion of that cost reduction. We'll see. Our corporate culture is to always push on LOE until we can produce these wells for free. We're always going to try to push on that envelope.
If you guys decided to add that seventh rig next year, where would that rig be placed? Sorry if I missed that, if you already went over it.
No worries. It'll be in the Midland Basin side, and it follows some of that two per 10,000-acre metrics that I laid out. If you had a seven-rig cage, you'd have six in the Midland Basin and one in the Delaware.
Okay. Just lastly, obviously great production growth in the third quarter 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 quarterly guidance is because any given quarter, if we've got a frack crew in one of our high-producing areas, we could have watered out or shut in 5,000 to 8,000 barrels a day of production shut in. I don't pay much attention to quarterly exits. It's probably reasonable to ask me what I exit the year at when we get there. Quarterly exit, I quite honestly couldn't even tell you.
Yeah, Richard, page five of our deck that we released
We'll give you a pretty good idea without giving you the exact number.
All right. Good enough. I appreciate it. Thank you.
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 lay out the production history of the wells. Most of them look to be older vintage, like at least a year online. I was wondering if it was safe to assume that most, if not all, these were completed with an older, smaller frack design. When you guys go back up there, probably with a newer, larger one, do you expect a meaningful uplift from what we see here?
You know, Sam, you might have heard me talk about this before, 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. What we brought with us was a bench strength of completion expertise on horizontal wells. The first well that we fracked in 2012 was with 1,500 pounds of sand per slick water at 100 barrels a minute. We've only made slight tweaks to that, as Mike Hollis outlined, over the time. When you asked 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.
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. Then just one quick follow-up in this area. Do you guys plan to test any Middle Spraberry or Jo Mill wells? It looks like, just eyeballing this, all these were Lower Spraberrys.
Yeah, I think there's a reasonable chance we can do a Middle Spraberry test in 2017. 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. 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. 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 any time soon, where we're seeing the really good results from the Lower Spraberry.
Okay. Makes sense. That's all I got. Thanks, guys.
Thanks, Sam.
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 pounds per foot, or will greater sand loadings be tested? 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, and that 18-2,000 seems to be about the right number. Everyone that's gone a little farther have come back just from once they start looking at the rate of return-driven economics of what they're spending and what they're getting. Each one of the zones will be different, and each one of the counties will be slightly different. To give a blanket answer as to what it is, it's really difficult to do that right now. 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. Over time, yes, we have gone to a higher sand loading, but we've also gone to lower rates at which we're pumping. We're not getting out and touching as much rock, and we're trying to get a higher Recovery factor, sorry about that, from the rock that we are touching near wellbore.
A lot of knobs are being turned right now, 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 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. You're seeing a lot of changes in the Delaware, more so than the Midland side.
Got it. Helpful. Thank you, have a great day.
Hey, you too. Thank you.
Thank you, Dan.
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, it looks like, in the third quarter, but you increased your borrowing base by $100 million. Should we read into that? I guess if you could repeat your broad outlook. You talked about M&A on what, if anything, you've seen on the minerals side.
Hey, Tim, this is Kaes here. Yeah, we've seen a lot more activity on the M&A front for Viper, starting at the end of Q2 into Q3 with the $126 million of acquisitions we did in the quarter. Most of that funded via the equity deal we did in July. Borrowing base was raised. 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, it's safe to say you're seeing maybe the bid and ask maybe starting to converge a little more?
Correct. I think we've done $300 million of total deals in two years, and 126 of them were in one quarter. I think that trend should continue based on what we're seeing.
Okay. That's all I had. Thank you.
I am showing no further questions at this time. I would now like to turn the call back over to Mr. Travis Stice 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.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program. You may now disconnect. Everyone, have a great day.