Diamondback Energy Inc (FANG) 2016 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy and Viper Energy Partners third-quarter 2016 earnings conference call.

(Operator Instructions)

I would now like to introduce your host for today's conference Kaes Van't Hof Vice President pf 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'll now turn the call over to Travis Stice.

Thank you, Kaes. Welcome everyone and thank you for listening to Diamondback and Viper Energy Partners third-quarter 2016 conference call.

Diamondback remains optimistic on a commodity price recovery, and has continued to 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 ducts to be completed by the end of 2016.

Our increased activity levels, combined with continued strong well performance, will enable us to grow production by more than 30%, and sets us up to continue to have multi-year organic growth at or near cash flow at current strip prices.

As a reminder, we recently increased our 2016 production guidance range to 41,000 to 42,000 barrels a day from 38,000 to 40,000 barrels a day, while keeping capital spend guidance unchanged. We have also introduced our 2017 production guidance of 52,000 to 58,000 barrels a day, which represents more than 30% production growth, as I previously mentioned.

Diamondback continues to deliver on best in class operating expenses and we recently lowered our 2016 LOE guidance to $5.50 to $6.00 per boe. We are pleased with the continue strength of our well results throughout our asset base, which Mike will elaborate upon later. Our organization continues to reduce DC&E costs. Third quarter 2016 cash operating costs are $9.15 per barrel, including cash G&A that is less than $1.00 per boe.

As illustrated on slide 5, Diamondback has a track record of accretive acquisitions and continues to evaluate deals in the Permian Basin. As shown on slide 6, we have amassed a robust inventory with five core areas capable of 1,000,000 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 yield flow and continue to evaluate additional mineral acquisition.

I will now turn the call over to Mike.

Thank you Travis.

Diamondback continues to post encouraging results, achieve new company execution milestones.

Slide 7 shows Delaware offset results that continue to improve and we now have four different zones that have successfully been tested through the drill bit. We are excited to get to work on our new Southern Delaware lease hold at the beginning of next year.

Slide 8 shows two new 10,000 foot camp 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 flow rate 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 1,000 Mboe.

Shifting to slide 9, we recently completed a three-well pad in Howard County targeting the Lower Spraberry, Wolfcamp A, and Wolfcamp B. These Wells had an average lateral length of 9,700 feet. The Reed at 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 1,000 Mboe into 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 anchorage 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 2016, we drilled three wells across the Northern Midland Basin with an average lateral lengths of 10,900 feet in an average of 11.5 days each from spud to total death.

We also drilled two Wells in Midland County with lateral length of more than 13,000 feet, our longest drilled to date. Longer laterals increased capital productivity in 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 million for a 10,000 foot lateral well and below $5 million for 7,500 foot lateral well.

Slide 15 shows reductions to our operating expenses since the peak in 2014. Looking back a year, we have reduced our LOE by 24%, to $5.37 per boe in the third quarter of 2016, due to improved pumping practices as well as service cost concessions. Illustrated another way, the first nine months of 2016 versus the first nine months of 2015 we have spent 9% less net dollars on operating costs while producing 27% more boe. As a result we reduced our LOE guidance range to $5.50 to $6.00 per boe compared to $5.50 to $6.25 per boe previously.

Diamondback continues to maintain a rate of return focused completion optimization program. We continue to test high-density near-wellbore frac, 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 will 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 average realized price per boe, including hedges, for the third quarter was $34.30.

During this 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 a proximally $126 million at the Viper level.

In connection with our fall redetermination Diamondback's lenders approved a $1 billion borrowing base under its credit facility, up 43% from $700 million previously. However, we again elected to limit the lenders aggregate commitment to $500 million. With over $160 million in cash and an undrawn borrowing base with $500 million in capacity, we have ample liquidity to fund our upcoming activities.

As shown on slide 17 Diamondback ended the third quarter of 2016 with the net debt to trailing 12 month 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 range of 41,000 to 42,000 boe per day, up 6% from July. With strong well performance driving the increased outlook our 2016 capital expenditure guidance was unchanged at $350 million to $425 million.

As part of that update we also introduce preliminary guidance for the full year 2017. At current strip prices, we expect to deliver annualized production growth of over 30% at or near breakeven cash flow.

I'll now turn to Viper Energy Partners which announced on October 27 a cash distribution of $20.07 per unit for the third quarter, up 10% from the second quarter of 2016 and represents a nearly 6% annualized yield as of November 7. Operators on Spanish Trail continue to decrease the current duct backlog. There are 14 ducts currently on Viper's acreage including approximately 10 wells that are normal inventory.

At the end of the third quarter of 2016 Viper have $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 will now turn a 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 accelerate 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 Glascock Counties, the increased acquisition at Viper, and are excited to begin development in the Southern Delaware Basin.

Operator please open the lineup to questions.

(Operator Instructions)

Neal Dingmann, SunTrust Robinson Humphrey.

Morning Travis, guys, Tracy; nice quarter.

Travis, two things here. First, you mentioned about perhaps bringing a seventh rig next year. Can you talk in broad terms, Travis, how you would attack? Now that you mentioned the great results in Glasscock, Howard, as well as even in Andrews, you had six to seven rigs running. How would you allocate those including the Delaware area?

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 to two in Howard County, one to two in Glasscock, and one to two or three in Midland County. And -- actually two to three in Midland County. The rigs are little fungible and one of the reasons that we pointed out that we've got five core areas that are capable of (inaudible) type of EURs is because we believe we've got lots of opportunities to deliver really nice returns to our investors.

Travis, in Howard, not just Howard, many of these areas you talk about, the Wolfcamp A and B, Lower Spraberry, a number of successful intervals is your drilling these. Looking at the Delaware, you were talking about doing mostly just Wolfcamp A. If you now, when you are targeting into Midland next year, will you multi-stack? Or how do you -- what do you think the focus will be when you look at Howard specifically, and Howard and Glasscock.

That's a good question and I wished I had a definitive answer for you. I could 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 and B or Lower Spraberry, it's up in the air until we get a little more established and seasoned production on our test in Howard County. One thing we do know is, 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, Northwest Martin and Northeast Andrews, it's going to be 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 so we've got really nice million-barrel wells that we're bringing online at an all-time low DC&E costs, and that will drive our production growth next year as well as staying within cash flow

Got it.

Lastly, you all seem to be a bit more full-cycle return driven that some other companies out there, which I like to see. When you see growth for next year, is it based on return driven? I guess the question would be, if you could 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? Or maybe just talk about, rather than ask what you guys would do if oil goes up or down, how you think about that including the hedges?

Sure. We have 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 two by one 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 in the 2017. Even though with those hedges in place, I think we have about 13,000 barrels hedged November, December this year and through the first half of next year.

That being said, though, our balance sheet, as I mentioned in my prepared remarks, we've got a fortress balance sheet; we have cash on hand right now, so we've got the ability to continue our rate of return and MPV-focused strategy on allocating capital. We don't mind accelerating activity into a recovery, and if we continue to see things that indicate commodity prices recovering, and our industry's recovering, then we can continue to accelerate activity there. In the same vein, though, if we see price pullback to $35 a barrel we have the ability to tap the brakes as well.

Makes sense. Thanks for the details, Travis.

Thank you Neal.

John Nelson, Goldman Sachs.

Good morning, and congrats on another quarter of strong execution.

On slide 7, I think you guys incrementally showed peer results 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. Could you 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 into Delaware in 2017, what targets, what horizons that will target early on?

Sure. When we bought that acquisition we underpinned it with two zones, the Wolfcamp A, the third Bone Springs, and Wolfcamp B. So those are the zones that we felt like we're de-risk. We recognize that there is upside in the second Bone Springs and I will let Russell address what we find out about the second Bone Springs since the acquisition time.

Specifically to your question on where that rig is going to get allocated, we will 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 got all those obligations satisfied we will switch to our more traditional development of multi-well pads and will be doing Bs and third Bone Springs and As all at the same time following the back half of next year.

Russell, you want to answer the second Bone Springs question.

Obviously we encouraged by the results we've seen out of the second Bone. There's possibly a limited number of tests based on the analysis we did before the acquisition. We thought there was potential there. Again, we are encouraged by the results that we have seen. As Travis was saying, our focus will really be on the Wolfcamp and the third Bone. One of the early wells that we drill there we'll core the intervals, and based on results of that core and early results we will make our decision going forward. Based on all set results in the area, we think the Wolfcamp A is probably the best zone, but we have seen some nice results out of the third Bone and Wolfcamp B as well.

Great. That's helpful.

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

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

Thanks, John.

Michael Glick, JPMorgan.

Good morning.

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

In general, Michael, I'll let Russell talk specifically, 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 have over 3,000 wells left to drill in our inventory and, as you pointed out, your opinion of conservative spacing. If our peers and industry prove up that tighter spacing works, well, then, we will be fast followers and you will see our inventory increased dramatically, if you believe some of the numbers the industry is touting out there in terms of development spacing.

In terms of what we are currently doing, we do have numerous tests going on. I will Russell talk specifically about those.

We have done down spacing tests in Lower Spraberry and other zones as well. It is still early. We will sit down with Ryder Scott, particularly in the Lower Spraberry, where we are just now actually have a full section of development on tighter spacing which we think is going to be the real test. Obviously we did some tests early on where we drilled three well pads or two well pads and early results were really encouraging. You really have to look at it in a full [collection] development mode to see what the true results are. I think we are getting close to having some of those results, and we will review them with Ryder Scott in a couple months. Based on our analysis and theirs as well, we will report what we are seeing.

Got it.

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

Sure. In general, this is 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 into each others' way. That's kind of how we set it up. If you look across our asset base, you can see each of those core areas; they all average some where between 10,000 and 15,000 acres. Notionally, inside those circles you can run two rigs in each of those areas.

Then the question of people. We are in pretty good shape; we are always looking to add a few key contributors and we try to build the organization to support a 10-rig program we're not far from that right now. We are 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.

Drew Venker, Morgan Stanley.

Good morning everyone.

I was hoping, Travis, on a follow-up to that, especially on the rig ramp. Can you talk about what your plans are in thinking of Delaware in longer terms beyond 2017? How much activity you'd expect? Any other infrastructure build, on considerations you have for further increasing activity in the Delaware?

I will answer your question on rig ramp and then I will turn to Kaes and let him talk about 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 levels 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, so we could get the 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 prices, et cetera, we can look to accelerate that.

I will let Kaes give us a thumbnail sketch of where we are on infrastructure out there.

On the Delaware, we bought the transaction, it came with 25,000 barrels a day of saltwater disposal capacity. I think we are 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 need on the cash processing side? Or is that handled, or it's building out?

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

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

We are always trying to optimize our results, either through both landing zone and stimulation. We have talked about that we've got a lot of different stimulation tests that we have done; again, most of those are fairly early in the results. Some of the early results are fairly encouraging and I think if you look at our current stimulations, on average we are probably in the 1,600 to 1,800 pound per foot range, given the high-density near-wellbore fracs. The data we've got so far, we think those look encouraging so we're continuing with those. As we have mentioned, it will be based on the return we're getting from incremental dollars that we are spending, and we'll continue to monitor results and make changes going forward as appropriate.

Thanks for the color.

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, we are trying to assess what we are doing relative to the returns we get for incremental dollars. When you hear us talk about results from these different techniques that we are trying, we always underpin it with, are we generating a greater return for our investors for the capital expended. And we hope the commentary for the industry navigates that way as well, too.

I wanted to add that, but thanks for your questions, Drew.

Thanks.

Mike Kelly, Seaport Global.

Thanks, good morning.

Travis, that has been some concern lately from investors here that you and the other Permian highfliers are growing activities back to the point where you are ultimately going to fill up trunk line capacity coming out of the Permian, I know you had some opinions on that, so just hoping to get some color there. And if there's some concern at Diamondback, on that front do you have the ability to go out and do some basis hedging today that might protect you? Or have you thought of that? Thank you.

Mike, I will let Kaes answer that question.

We released today that we have 24,000 barrels a day of basis protection for next year, in 2017, and 10,000 per day for 2018. I think were 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, protect us financially via those basis hedges. We're active and we are looking at it.

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

It's just intermarket. We put 10,000 barrels a day on at about $0.85. I think we are happy with any number under $1.00 there in that market.

Okay. Great.

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

I will let Russell answer specifically, but in general term let me tell you what we are seeing in Lower Spraberry. It does appear that it is drawing its own curve, which is atypical for most of the unconventional sales 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 shallower. We've got now, as we pointed out in my 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 on incorporating the results from all the other Lower Spraberry wells in Howard County.

Russell, do you want to add anything to that?

For the most part, the profile that we are seeing is fairly typical. The majority of the Lower Spraberry wells in Howard County, we have done data traces 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-declined 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 read-through well pad; the next couple weeks we will get all that data in and we'll look to see what occurred during the stimulation and we will make adjustments potentially to both the landing zone and the stimulation. We are fairly optimistic at this point that we can do some things to get higher initial rates, but again, as we said, we are pleased with what our projected EURs are. And it's fairly early time, but we have got opposite operator data that probably has got a year or more 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.

Pearce Hammond, Simmons.

Good morning, and 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? And then, as you think about 2017, where do you see things maybe getting tight? Or do you see any inflation out there?

I could 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 increase 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. We know our business partners primarily on a 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. With that being said, we just don't see a whole lot of reason on the pressure pumping side for costs to go up in 2017 if we are going to be in the range bound of the $45 to $50 barrel world. Rigs, we have plenty of drilling rigs, no worries there for the foreseeable future. Those are really the two big spend items and we monitor those closely.

Thank you.

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? And even to some color between the Delaware and the Midland, if you can provide it?

You know Pearce, we have a pretty consistent record on not talking about transactions that are underway, but I could give you some high-level thoughts. If you go back to our offset date, 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 warrant or allowing us to block up and drill longer laterals whether they are outright acquisitions or swaps. And there are 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, it's just a whole bunch of opportunities there in the Delaware. I don't know if there is buyer fatigue or not yet in the Delaware, but I can tell you that I don't think that all 15 to 20 of the private equity-based companies are going to go public in the next 12 months. They are all looking for some form of liquidity event for their investors. Like I said in my prepared remarks, Diamondback is in that game and we continue to look for ways to generate exceptional returns to our investors.

Thanks, Travis and congrats on a solid quarter.

You bet, Pearce. Thank you.

Jeff Grampp, Northland Capital Markets.

Morning guys.

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? What you all -- obviously, the encouraging results and how are some of the other areas? I want to get a greater sense of what the ultimate data set is internally within Diamondback for those types of wells.

Jeff, this is Mike.

We have been doing testing since we 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-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 have 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 have got a subset of data that will be coming to us over the next several quarters that we ought to be able to help diagnose what some of the better techniques to do going forward. 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. In general, we are looking at that 1,600 to 2,000 pounds per foot sand concentrations and more high-density near-wellbore completions.

Okay. Thanks for that, Mike.

Then, on the longer laterals, looking at slide 12, it looks like you guys are keeping the EUR per foot constant across various lateral length, and then you guys talked about doing some even 13,000 footers. Is that holding pretty consistent in terms of not seeing any EUR degradation as you stretch the laterals out?

Outside the data we have seen so far is pretty encouraging. The one thing, when you get the real long laterals, particularly in the high productivity zones, sometimes you might be limited early on how much total fluid you can move, so you might not -- the first few months you probably are not seeing quite as high peak rates on the longer laterals. But the data that we have 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.

Okay. Great. I appreciate the detail. That's it for me thanks.

Michael Hall, Heikkinen Energy Advisors

Thanks. Good morning.

I just wanted to 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. Did I hear that right? And number two, can you talk through what gets you more interested in putting rigs in that area?

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

It does sound like that area will get some capital in 2017 then. Is that fair to say?

And again, Michael, we 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's really just when we got down to three rigs thinking we were going to go to one that we stop 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, Southern Midland didn't get a call out. I was curious how that's fitting in the portfolio today? And what is needed to keep that acreage whole?

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

Okay. That's helpful.

I wanted to zero in a little bit on the Wolfcamp B and Howard County. As you look at pressure drawdown between that and A, is there a material difference in the two intervals? And the first well versus the second well, can you talk about the comment that the second is outperforming? What is leading you to believe that this early on? Just some more commentary around that.

Yes, if you compare Wolfcamp A and Wolfcamp B, if you look at the IRP what we reported for the Reed well this time and for the Hodnett well the last time, there's not much difference in a 30-day IP between A and B. The B, your pressure draws down a little quicker, a little steeper decline, and that's why we think long-term the Wolfcamp A would be the better zone.

On your question comparing the second pad to the first pad, again, it's fairly early, the rates are not that much different but the pressure is holding in quite a bit better on the Reed well than it did on the Hodnett well. Whether that is due to the high-density near-wellbore frac on the lead well, or whether it's just a geologic difference, we don't know yet. So far, and again it's very early, we'll probably have three weeks of total production on these wells. At least very early on, the Reed Wolfcamp B does appear to be outperforming the Hodnett Wolfcamp B.

Got it.

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

There are really two 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. We have 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; increase our total net acreage in the area. Right now we're fairly encouraged by the success we have had on both of those fronts.

What is your current gross and net, do you have that?

I don't have that number with me. It has increased since the initial acquisition.

I will follow up.

Actually, one more if I could squeeze it in. You guys in the past have talked about a 100,000 barrel a day capacity from the asset as we firmed up 2017 a bit more here. I wondered if you had any more views as to how quickly you can get to that level?

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

All right. I figured I would give it a shot.

It was a good effort.

Gail Nicholson, KLR group.

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 link via acreage [to offer]? And what percentage of that inventory do you think is going to always be a shorter lateral?

I think it's probably about at least 30% of those that would probably end up being shorter laterals, and a lot of those, I will say, are Spanish Trail Lower Spraberry, where, just due to the acreage and 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 will eventually be able to block up either through drilling joint wells with other operators or making acreage trades. But we've still got those in our inventory at short laterals because we haven't actually inked any of those deals yet but we continue to work on them.

Great.

Turning over to Glasscock County, of the four wells that were turned online, two of those are flowing naturally, and actually they are 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 do you think Glasscock in general might have more well flow naturally versus the rest of your Midland Basin acreage?

I think Glasscock, there's a little higher GOR area; most of the wells do flow naturally for some period of time; it varies from well to well, maybe it's a month, maybe as long as three or four or five 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 one flows longer than the other. I will say when you actually look at the data between the two zones, there is 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 that can cause a well to stop flowing and at that point we go ahead and run the ESP. Probably not as much difference as you might be thinking from looking at the data at a high level.

Okay. Great, thank you.

Jason Wangler, Wunderlich Securities, Inc.

Travis, just curious, talked about service pricing and things. How is it looking as far as equipment availability? You mentioned obviously you're not really replacing things right now; obviously activity for you guys and everybody else is increasing. How are you seeing that side of it looking as you continue to pick up more and more over the next couple years?

Jason, this is Mike Hollis, I will take this one for you.

As we mentioned in the past, as long as the Permian basin is pretty much the only bellwether right now, adding any activity short of the Scuba Stack area, availability of iron typically isn't a problem right now. Very short-term, if you call something out tomorrow, maybe a difficult thing; but if you have a week or two getting iron and people usually is not an issue. We see that coming more later, second half of 2017 or 2018, when some of the other basins pick back up and we are all competing for the same services at that point. But for right now, service equipment and people are easily accessible.

Thanks, Mike.

The old rule of thumb is, everything has wheels on it, so is it mostly bringing things into the Permian, as you said, being the bellwether from other areas? Because I assume 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 is correct. We still see trucks coming into the basin every day.

Okay. Great. I will turn it back.

Richard Tullis, Capital One Security.

Thanks, good morning, everyone.

A couple quick questions: Travis, things have done a good job lowering cash OpEx over the past year or two, or even going beyond that. What's the outlook for 2017, given start up of drilling in Southern Delaware Basin? Any capacity to lower further at that point?

We gave -- did we give guidance for 2017 OpEx? We haven't done it yet. LOE is one of those things 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 the ratio look really good.

LOE costs, Richard, are typically more sticky than what you see on the service cost DC&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. We believe that we are, if not moved down slightly, but we're at that asymptotic portion of the cost reduction, and we will see. Our corporate culture is to always to push on LOE until we can produce these wells for free. So we're always going to try to push on that envelope.

And then, 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 will be in the Midland Basin site, and it follows some of the 2 per 10,000 acre metrics that I laid out. If you were at a seven-rig cadence, you'd have six in the Midland basin and one in the Delaware.

Okay.

Lastly, great production growth in the third quarter, with 32% quarter-over-quarter growth. What was the exit rate for the quarter, if you are 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, in any given quarter if we have a frac 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. The quarterly exit, I couldn't even tell you.

Richard, page 5 of our deck that we released will give you a pretty good idea without giving you the exact number.

Good enough, I appreciate it. Thank you.

Sam Burwell, Canaccord Genuity.

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 old or vintage, like at least a year online. I'm wondering if it was safe to assume most if not all of these are completed with an older, smaller frac design? And when you guys go back up there, probably with a newer, larger one, do you expect the 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 Barnett Shale, Marcellus in 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 1,500 pounds of sand per slickwater at 100 barrels per minute. We have only made slight tweaks to that, as Mike outlined, over time.

When you ask me about what we are going to do with these new completions in Northeast Andrews and Northwest Martin, the most likely thing we will 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 five or gen three, that's where we started in 2012.

Okay, got it. I appreciate the color.

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 Spraberry.

Yes, I think there's a reasonable chance we would 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 and the area and several of those wells are probably within a mile of our acreage and the results have been very encouraging. We are pretty certain we have Middle Spraberry potential on our acreage. Again, the IPs on the Middle Spraberry have not been as good as the Lower Spraberry, but the EUR still looks good. We will probably test it at some point, but with all of the offset activity we've gotten in the area, we feel like the zone has proved up on acreage and so there's not a real need for us to step out and test anytime soon, where we are seeing really good results from Lower Spraberry.

Okay. Makes sense. That's all I have. Thanks, guys.

Dan McSpirit, BMO Capital Markets.

Folks, good morning, and thank you for taking my questions.

A quick follow-up on the enhanced completion. Has the efficient frontier been reached yet in the Permian basin with 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 [the] in any one zone because of unique rock characteristics involved?

Dan, this is Mike. I will take that.

The answer to every one of those questions is basically, yes. We don't think that we have found the efficient frontier just yet. You have seen some folks really push the edge and have pulled back in that 1,800 to 2,000 seems to be about the right number. Everyone that's gone a little farther have come back 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, so 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 are migrating to more of a stack and stagger approach to a lot of the zones to give ourselves a little more distance within the same number of wells per section; we get a little 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 have also gone to lower rates at which we are pumping, so we are not getting out and touching as much rock and we're trying to get a higher recovery factor from the rock that we are touching near wellbore.

A lot of knobs are being turned right now. To say that we have hit that final frontier here in the Midland Basin is hard to say. We are a little farther along than over in the Delaware, where you are starting, you are 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 (inaudible)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, Dan. Thank you.

Tim Rezvan, Mizuho Securities.

Good morning folks.

Most of my questions have been answered. I have a quick one: 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? If you could repeat your broad outlook, you talked about M&A, and what, if anything, you've seen on the mineral side?

Hi, Tim; it's Kaes here.

We've seen a lot more activity on the M&A front for Viper starting at the end of Q2 into Q3 with $126 million of acquisitions we did in the quarter, most of that funded via the equity deal we did in July. The 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 kept at Diamondback, and simply do deals that are accretive to that distribution.

Okay, so it's safe to say you are seeing [maybe didn't ask, maybe] starting to convert a little more?

Correct. We've done $300 million of total deals in two years and $126 million were in one quarter. I think that trend should continue based on what we are seeing.

Okay. That's all I had. Thanks.

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 and you may now disconnect. Everyone have a great day.