Diamondback Energy, Inc. (FANG) Q3 2015 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Diamondback Energy and Viper Energy Partners Third Quarter 2015 Earnings Call. At this time, all participants are in a listen-only mode. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Adam Lawlis, Investor Relations. Sir, you may begin.

Thank you, Candace. Good morning and welcome to Diamondback Energy and Viper Energy Partners joint third quarter 2015 conference call. During our call today, we will reference an updated investor presentation, which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, CEO, and Tracy Dick, CFO, as well as other members of our executive team. 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 and the reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice.

Thank you, Adam. Welcome, everyone, and thank you for listening to Diamondback's and Viper Energy Partners' third quarter 2015 conference call. Since the beginning, Diamondback has focused on stockholder returns, best-in-class execution, low-cost operations, and maintaining a conservative balance sheet. Today, this focus enables us to be in a position of strength as a stable and liquid company with high-quality acreage and a deep inventory of profitable horizontal locations. As I've said in the past, Diamondback is not about growth for growth's sake. Accelerating activity in a depressed commodity environment is not a prudent use of stockholders' capital. As you recall, at this time last year Diamondback communicated that we would not accelerate activity until service costs recalibrated and commodity prices improved. We continue that same capital discipline today while at the same time we keep improving our efficiencies. We will average four rigs during the fourth quarter and are currently running one completion crew. At this time, we intend to enter 2016 operating four horizontal rigs and one completion crew but we will adjust our plans as the environment warrants, consistent with our practice of capital discipline. As illustrated on slide five, we've run sensitivities from two to eight rigs in 2016 depending on oil prices. We have also shown the number of economic locations at each commodity price range, highlighting Diamondback's high-quality inventory. Our historical decision to manage the balance sheet in a conservative manner has put us in a position of strength today as we look at the different outcomes for next year. We would like to see a sustained shift in commodity prices before adjusting capital allocation in a meaningful way. Diamondback has a track record of accelerating quickly when rates of return improve. We will provide more fulsome plans for 2016 in the coming months. As mentioned in last night's press release, we now consider the Wolfcamp A and Middle Spraberry formations derisked on our Spanish Trail and Southwest Martin Country acreage. Slides six and seven show Diamondback's completions in the Wolfcamp A and Middle Spraberry as well as those of offset operators. Our first operated triple-stacked well was completed in Spanish Trail. The Trailand A Unit 3906, Lower Spraberry, Wolfcamp A, and Wolfcamp B have a combined average 30-day IP of 3,200 BOEs a day. The Wolfcamp A is tracking an approximate 800,000 BOE type curve while the Lower Spraberry and Wolfcamp B are performing in line with our Ryder Scott type curves for Midland County of 990,000 BOEs and 638,000 BOEs respectively. Also in Spanish Trail, we completed our first Middle Spraberry test as a stacked lateral in conjunction with the Lower Spraberry well. The Spanish Trail West 705 Middle Spraberry has a peak two-stream 30-day IP of 851 BOEs a day. We are drilling our first four-well stacked pad in Southwest Martin County targeting the Middle Spraberry, Lower Spraberry, Wolfcamp A and Wolfcamp B and expect to have results early next year. During the third quarter we began horizontal development of our Glasscock County acreage with a three-well pad that targets the Wolfcamp A, B and Lower Spraberry in a wine rack pattern. We intend to complete these wells later this year, and are currently drilling our second pad there. We will also test this wine rack concept on our recently acquired acreage in Howard County at the end of this year with a three-well pad that will target the Lower Spraberry, Wolfcamp A and Wolfcamp B. Last night we announced that we expect our capital spend to be at the lower end of the guided range as we continue to do more with less. We now anticipate 2015 production to range from 31,000 to 32,000 BOEs a day, up from 30,000 to 32,000 BOEs a day previously. Diamondback's track record for peer leading efficiency and execution continues, resulting in more economic wells and driving differential returns for our stockholders. Slide eight shows that in our primary development areas in Midland, Martin and Andrews County, Diamondback continues to lead drilling efficiency coms when compared to offset operators. Just last week we reached 17,400 feet total depth on a 7,600-foot lateral well in Northwest Martin County in approximately nine days. I'm proud that as we've begun development in our new Glasscock County area, our first three wells reached TD faster than offset operators. Slide eight also shows our peer leading operating expenses. Our LOE in the third quarter of 2015 was $7.08 per barrel, a 6% reduction in the second quarter of 2015. The decrease in LOEs is attributed to our continued efforts to implement best practices on acquired acreage, reduce failure rates and optimize costs. Slide nine shows the reduction in LOE since their peak, as well as current cost savings to drill complete and equip a 7,500-foot lateral. We continue to capture incremental savings due to cost concessions and permanent efficiency gains, with current well costs down 25% to 35% from last year's peak. Average drill complete and equip costs for the year are expected to be between $6.2 million and $6.4 million for 7,500-foot lateral, as leading edge well costs now trend between $5.5 million and $5.8 million. Diamondback has built a high quality acreage base that puts us in a position of shrink with ample inventory, stability and liquidity to continue to differentiate ourselves in a disruptive environment. With these comments now complete, I will turn the call over to Tracy.

Thank you, Travis. Diamondback's adjusted net income was $26 million or $0.40 per diluted share. While much of our better than expected earnings was attributed to higher production and lower costs, some of it is due to lower DD&A from the impairment charge we recorded in the second quarter of 2015. As a result, we are revising Diamondback's DD&A guidance to arrange at $17 to $19 per BOE from our guidance prior of $19 to $21 per BOE. Diamondback's adjusted EBITDA for the quarter was $110 million, which is slightly above EBITDA in the third quarter of 2014, despite price realizations being significantly stronger in 2014. Our third quarter average realized price per BOE, including the effective hedges, was $47. Diamondback continues to have peer leading cash margin, driven by our focus on execution and cost optimization. Slide 10 shows that in 2Q 2015, cash margins exceeded the pure average by over 30%, while on slide eight, we show that year-to-date operating expenses were 17% lower than the pure average. Also on that same slide, we show that Diamondback continues to be one of the leanest operators, with year-to-date G&A nearly half of the pure average, and we generated more production per employee than our peers in 2014. In the third quarter of 2015, our cash G&A costs were $1 per BOE, while non-cash G&A costs are $1.40 per BOE. We spent approximately $80 million for drilling completion and infrastructure, and approximately $22 million for acquisition. During the third quarter of 2015, Diamondback achieved positive free cash flow for the second time in company history, excluding acquisition. We now expect our capital spend to be at the lower end of the previously guided range of $400 million to $450 million for 2015. Our peer leading leverage and track record of conservative financial management position us favorably in this environment. As part of the fall redetermination, our agent lender recommended a borrowing base increase from $725 million to $750 million. We have elected to maintain the $500 million commitment. At the end of the quarter, Diamondback has $529 million of liquidity, including $490 million available on our revolver. I'll now turn to Viper Energy Partners, which announced a cash distribution of $0.20 per unit for the third quarter. This distribution represents an approximate 5% yield when annualized based on the October 30 closing price. Viper has no minimum quarterly distribution or complex ownership hierarchy. The majority of cash flow is returned to unit holders through quarterly distributions, providing upside when oil prices rebound. Slide 13 shows how Viper's distribution remains resilient despite lower oil prices due to organic production growth. Spanish Trail remains one of the most economic areas in the Permian Basin and we expect the operators will continue to drill there. Viper had $29 million drawn on its revolver as of September 30, 2015. As part of its borrowing base redetermination, Viper's agent lender recommended an increase from $175 million to $200 million. Turning to Viper's guidance, we are raising production guidance to a range of 5,000 to 5,200 BOE a day, up from prior guidance of 4,800 to 5,100 BOE per day. As a reminder, Viper does not incur LOE or capital expenditures. We've also lowered Viper's DD&A guidance for 2015 to a range of $17 to $19 per BOE from $20 to $22 per BOE previously. This is due to an increase in its reserves. I'll now turn the call back over to Travis for his closing remarks.

Thank you, Tracy. This quarter was marked by improved performance in all areas of our business, efficiency gains in drilling performance, optimized costs and continued improvement of our average well. Our conservative financial management and capital discipline put Diamondback in a position to weather the low current commodity price environment, and we're poised to accelerate when price recovers. Before we turn the call over to Q&A, I want to recognize each of our 139 employees for all the hard work they've done to continue our track record of execution and low-cost operations. The third anniversary of Diamondback's IPO was earlier this year in October. It has been an amazing three years, filled with many exciting success stories. I firmly believe Diamondback's best is yet to come. Operator, please open the line for questions.

Thank you. [Operator Instructions] And our first question comes from John Nelson of Goldman Sachs. Your line is now open.

Good morning, and congratulations on a very strong quarter.

Thank you, John.

I think after the August equity raise, a lot of us were expecting an acquisition announcement was probably looming. I'm sure to an extent you're limited in talking, but can you talk just generally about what the acquisition pipeline looks like currently in the Permian, and what you think your acquisition capacity could be from a financial standpoint?

Well, John, that's a good question, and you know my track record is we typically don't talk about any acquisitions that are currently ongoing. But I can tell you with regard to the pipeline, we still continue to see good opportunities out there. I'll tell you that the spread between bid and ask is probably still pretty wide as evidenced by not a lot of transactions occurring lately. But I also think it's reasonable from my stockholders to expect our fingerprints are on every transaction that occurs out here in the Permian. Because as I've said before. You are either in that M&A game or you're out of it. And Diamondback is active both doing the small bolt-on deals that we announced this quarter, as well as the larger deals. In terms of capacity, we don't typically screen our deals by on how big they could be. We look at the quality of the rock. And we believe that if we identify high quality rock, that our investors will appreciate our execution prowess and our financial performance in converting that rock into cash flow. And we really don't filter the deals on how big or how large they could be.

That's helpful. Then I wanted to switch over to slide 5. I was hoping you could speak to how rig allocation on slide 5 is the scenario analysis for different commodity prices? I was hoping you could speak to how rig allocation between your different operating areas might look in different scenarios?

Yeah. We've consistently said the Spanish Trail has some of the best economics of any shale development in the Lower 48, especially when you consider the impact of the mineral ownership that the Viper has and Diamondback owning 88% of Viper. So we'll always try to keep two rigs at any commodity price in Spanish Trail. And then as you look towards entering 2016 with four rigs, we'll have the two rigs in Spanish Trail and we'll have two rigs both, one rig in Howard, one rig in Glasscock County, and then we'll bounce between those two new development areas into some drilling in Northwest Martin County or Northeast Andrews County.

So would a fifth rig be added then back to - which area as we kind of stepped up that chain?

Yeah. You start moving up, we've got acreage position in Howard that could very easily support two rigs. We've got an acreage position in Glasscock County that could easily support two rigs. We'd keep the two in Midland County and we'd probably have one or two rigs in Northwest Martin County or Northeast Andrews County.

Okay. That was very helpful. Thanks again, and congratulations on the quarter.

Thanks, John. And guess just to close that thought out, and as you get to higher oil prices, $65 to $75, we'd probably allocate a rig back down in Upton County.

Thank you. And our next question comes from David Kistler of Simmons & Company. Your line is now open.

Good morning, guys. A quick follow-up on the acquisition comment. Can you talk a little bit about where you acquired acreage? And does any of that overlap into Viper and add some additional inventory to that portfolio?

Yes. Dave, I think we talked about $22 million worth of acquisitions. Those are all bolt-ons in and around mostly Midland County acreage. And yes, there's a portion of that acreage that Viper has the - owns the minerals. So it was accretive on both fronts, both Viper and Diamondback. It really underscores our continued efforts to build our high quality inventory, where we're doing these small bolt-on deals. And as I was talking to John just previously, we're still looking at the bigger deals as well. I believe that we've got the capacity to identify the rock and execute on the rock on just about any deal size but the blocking and tackling that's required to do these bolt-on deals is kind of a day in and day out activity.

I appreciate that. Then also kind of thinking about slide five, but more so trying to tie it to capital program, if we kind of look at this year and back into the numbers, it feels like about $100 million of CapEx in aggregate equals kind of one rig. Is that the right way to think about the CapEx that might be allocated to each one of those scenarios based on how you've outlined the rigs?

Yeah, Dave. That's a good rule of thumb. Just to clarify that, that would also include drill complete, equip and any associated facilities and infrastructure that we'd have to do. So somewhere in that $100 million range per rig.

Absolutely. And then just to understand the scenario analysis, when you look at those, you've highlighted in your portfolio before that returns are 40% to 70% at $40 oil in obviously Spanish Trail and whatnot. Is that the metric you need as you ratchet up in each one of these? Or is this really PV10 analysis?

It's more of a PV10 analysis, Dave, just to give our investors a full-scale look at the inventories that we have in our control.

Okay. I appreciate that. Then one last one just as you think about the capital budget for this next year, are there specific metrics that you're focused on in terms of maybe a debt-to-EBITDA leverage ratio that you'd want to stay within if you're going to outspend cash flow a little bit? Or is the mandate largely live within cash flow with the exception of maybe acquisitions, et cetera?

Good question, Dave. It's actually about four of those things you just laid out there. We consider in our capital allocation process, we consider leverage ratio, and we strive to stay below two times debt to EBITDA. We also look at our borrowing base, and as Tracy outlined, we conservatively took only $500 million out of the $750 million borrowing base. We try to maintain typically below 50% draw on a net revolver base. We look at cash outflow spend. We try to minimize that. Certainly the lower and lower the commodity price goes. And so we try to mix all those together along with lease obligations and drilling obligations and come up with an allocation process. So it's not just a single metric we look at. It's really a combination of all of them, but all of those that I just mentioned. And with our stated objective of rated returns back to our shareholders, we try to allocate capital accordingly.

I appreciate that. One last one, if I can just sneak it in. Just looking at the growth you've delivered year to date, if you tapered down to a two or three-rig program, would that be considered kind of maintenance CapEx and maybe put you towards a flat production? Or would that be maybe a slight uptick?

I think when you go down to two to three rigs, again, we've not laid out in detail what our drilling plan is going to look like for 2016, but if you were at two to three rigs, you ought to expect more of a flattish production profile for next year.

Perfect. Well, I really appreciate all the added color. Thanks for letting me sneak in so many questions. Take care.

You bet, Dave. Thank you.

Thank you. Our next question comes from Mark Lear of Credit Suisse. Your line is now open.

Good morning, guys. On the first results in the A and the Middle Spraberry, just wanted to get a sense of how you would now rank the target opportunities across your key focus area by zone?

Yeah, Mark. The Wolfcamp A results we thought turned out really well based on our results and those of other operators. The Wolfcamp A is certainly looking pretty good, not quite the quality of the Lower Spraberry, but seems to be outperforming the Wolfcamp B in this area. Of course we've always talked about how good we think the Wolfcamp A is in Howard County. So I think as you look at our focus looking at going out in 2016, obviously the Lower Spraberry will still be the main focus, but I think you'll see more Wolfcamp A wells come into the mix. On the Middle Spraberry, as we've mentioned before, the Middle Spraberry test we did is on the western side of Spanish Trail. We think that in general the performance improves as you move to the east, and I think you see that in the results of some other operators as well. So kind of on the Eastern side of Midland County I think you'll see a few more Middle Spraberry wells come into the mix as we continue to test that zone on some of the other acres.

And you alluded to the Lower Spraberry still being a focus in 2016. If you had to ballpark it, how would you be allocating capital by those different targets?

Yeah, but I think we're probably still looking at something on the order of 60% of Lower Spraberry wells. I think in a real low price environment that number could move up if oil prices improve. I think you'd see us continue to delineate some of the other zones and maybe that percentage of Lower Spraberry wells would move down a little.

Gotcha. And just changing too in a little bit, just recalling some of the conversation on the 2Q call about some of the Lower Spraberry spacing tests you had in the works, some impressive early time production results there. I was just curious how the performance there has progressed, and maybe some of the other tests you're currently working on?

Yeah. I think it's probably still a little early. We had reported some results off of two and three well pads spaced at 500 feet. We just recently completed five wells, essentially developed half a section at 5000-foot spacing. The last of those wells have just recently come on line. So it's still a little early to gauge the true results there. Some of the earlier wells were watered out. They've come back nicely, so I think with the data we've got so far, we're comfortable in saying that on average we're meeting or maybe slightly exceeding that Ryder Scott type curve. We do have some - an additional kind of four-well test coming up. The last of those wells will be completed probably in the first quarter of 2016. So it'll be into 1Q or 2Q before we have some results there on 500-foot spacing. We were kind of doing some 660-foot spacing tests in northwest Martin that again - probably looking at 2Q before we have some meaningful results there.

Gotcha. Thanks, Russell.

Thank you. And our next question comes from Neal Dingmann of Suntrust. Your line is now open.

Morning, guys.

Hey, Neal.

[indiscernible] or Russ, one of the guys, obviously just when you think you can't squeeze out any more costs, I mean it's pretty impressive that 5.5 to 5.8 along with the nine days. Your thoughts on are you still going to be able to put some pressure on the Service companies out there. And then secondly, just on these efficiencies, can you really get anything down, nine days seems incredible. Can you get anything under that?

Well, first of all, from the Service costs, the Service sector has responded in a pretty fulsome way in 2015 with cost concessions. I still maintain that as long as there's idle equipment in the yard, there is pressure from the Service sector guys to put that arm to work, which means they have to come down on costs. I can tell you probably for just planning purposes, it feels like this is sort of the bottom. When they move marginally down, if commodity prices continue to soften or really to stay where they're at right now. But I think just for planning purposes, it sort of feels like the bottom. In terms of the efficiency gains, I'm really proud of the organization that they continue to do more, almost on a quarter basis. And I know we've got a culture that says we're going to do better on the next well, than we did on a prior well. And my expectations until we can drill complete and deplete one of these wells all in a single day, we're going to continue to push that efficiency envelope until we can achieve that. So I do think that we've made some great strides this year we making permanent some of these cost savings through the efficiency gains we've made. But we are always going to try to continue to push that envelope.

You said about the service to anybody. Either the rigs side or frac side, would anybody let you lock into longer term deals around these levels?

We've had conversations that way. I still believe that even if I locked in today, I'm going to be locking in higher costs than what we are going to see for a longer period of time. So I believe that we are getting extremely good service at extremely competitive pricing right now. And for Diamondback I believe we're just going to play the low cost guys, going to deliver good service right now for the near future.

Got it. And then just lately, I know with what you have with Viper and stuff, it just makes sense with your minerals to drill in the core area, and I know how set you are in Howard. What about your southern acreage? Any thoughts of doing some things down there any time you know down in Upton any time soon?

Yeah. I think I was kind of addressing that a little earlier in one of the questions and I said, because I kind of forgot about Upton County. Upton County's going to need probably $65 or $70 oil before we'd allocate capital down there. You know, that was our original development area. And we're proud that we started that whole horizontal renaissance down there. So we have an emotional tie to it, but the economics don't support developing down there until commodity prices improve, probably somewhere in that $65, $70 range.

Makes sense. All right. Great quarter, Travis.

Thank you, Neal.

Thank you. And our next comes from the line of Mike Kelly of Seaport Global. Your line is now open.

Thanks. Travis, I like the scenario analysis on slide five. And it looks like you've kind of already unhid a couple columns here on the CapEx and capital allocation front. I was hoping you could maybe unhide the growth column here. And then just curious on what the growth, what the associated growth is which each one of these scenarios. You already kind of hinted you're flattish in two to three rigs. Maybe you could talk about the 45 to 55 or the 55 to 65. Thanks.

You bet, Mike. And I appreciate the effort trying to get me to disclose 2016 there, but we're not ready to talk about growth ranges yet for 2016. I mean, we've still got some decisions we have to make on which well types we're going to drill, whether we drill on stacked laterals or we drill all one zone. And we've got to see what the commodity price is going to do as we exit the year. So I promise you when it's time to talk about 2016, I'll, as you pointed out, I'll unhide the columns. And we'll give you all the details that you need to put your model together. But still premature right now.

Sure. Fair enough. Maybe we could just talk about the production trajectory going into Q4. I think if I take your updated full year guidance, it looks like price has sequential decline going into next quarter. And just wanted to get some color on some of the variables in Q4, whether you're implying that you're going to build DUCs or you've got some pad drilling. Just a few things that could be going on there, and I wanted to get some color.

Sure, Mike. Well, yeah, you're right in the fact that we'll probably with one completion crew and four drilling rigs, we're going to be building DUCs at a moderate pace, probably somewhere between 10 to 15 by the middle of next year. And we'll build a couple as we exit this year as well. There's a couple of other macro events that go on. The first, if you just do the math and if you take the upper end of our production range guidance, you're going to see that relative to where we are right now, it's close to flat quarter-over-quarter expectations. We don't know exactly if it's going to play out that way because there's also some things that typically incur in the fourth quarter that we were trying to take into account. One specifically is that we never can count on weather, but we know there's usually a weather event somewhere in December, and that can impact production relatively significantly. Two is the fact that we're drilling most of our wells on multi-well pads right now, and to the extent that one of those pads slides into or out of the quarter, it could have a production volume impact. And three, we also have seen historically that the service sector tries to get a few days in on vacation with Thanksgiving and Christmas. So our utilization rates during the fourth quarter typically drop a little bit. So we try to take all that into account. And again, we've never guided towards the quarter's production volumes because of some of those things that we just outlined. I know we've only got eight weeks or so left in the year, but those are the things we're considering.

That's real helpful. Thanks a lot, guys.

Thank you. Our next question comes from Gordon Douthat of Wells Fargo. Your line is now open.

Thanks. Good morning, everybody. My question, and we talked about this a little bit last night, but my question has to do with the development configuration as you contemplate your 2016 program, specifically regarding the stacked well development configuration. I guess my question is do you notice any differences on the productivity side of the equation by doing a pad on the stacked well configuration across the various benches versus just focusing in one bench? So first on the productivity side. Then secondly, on the efficiency side, do you realize any efficiencies from drilling in that configuration as opposed to drilling within one bench across a single pad?

Yeah. I'll answer the second question first. There's really no efficiency difference whether you drill three stacked laterals or three laterals in the same zone. The efficiency is basically the same. On the productivity side, as you know, we've always indicated that we thought on the eastern side of the basin it may be more important to drill stacked laterals because of the relative absence of frac barriers between the intervals. So our plans have always been to start out going stacked laterals on the east side of the Basin, Howard and Glasscock Counties, and as you see from our press releases, we've tested some stacked laterals on the west side of the Basin, and we've got a four-well stack we've drilled in that southwest Martin County acreage. And we're actually going to frac two of the intervals, first the Wolfcamp B and Lower Spraberry and then come back about a month later and frac the Wolfcamp A and Middle Spraberry. And we'll tag those fracs and monitor the results to try to get a better gauge of how much communication we're seeing vertically between those zones. And so based on tests like those, hopefully we'll make the best decision going forward. But if you ask us right now, we probably still lean towards for the most part drilling same zone on the western side of the basin and stacked laterals on the east side.

All right. That's all I had. Thank you.

Thank you. And our next question comes from Jeff Grampp of Northland Securities. Your line is now open.

Good morning, guys. I wanted to kind of get your thoughts on some recent activity we've seen in the industry with your neighbors at Spanish Trail getting some good 500-foot Lower Spraberry results in the same landing zone. I'm just kind of wondering how you guys are viewing perceptivity of a concept like that, and then just kind of generally, your interest in any sort of operate test of a similar concept?

Well, as you know, we just talked about the - we drilled those five wells across it at 500-foot spacing in Spanish Trail, and as I mentioned, the results there are very early. We did land those essentially all at the same landing point, and so we'll continue to monitor those results. And we may do some tests as well where we stagger the landing zone within the Lower Spraberry. And we've had several other tests as well where we've done a two-well pad or a three-well pad at 500-foot spacing. And I think we show kind of the general results of those - I think it's one of the slides in the appendix. Actually, I think it's slide 18 where we show the average result of all the wells drilled at 500-foot spacing versus the ones drilled at 600-foot - 60-foot spacing versus what we called singular wells, which are wells that don't have an offset well within, say within 1,300 feet. And if you look at that, you don't see really any material difference between the ones that are at 500 feet versus 660 feet. But as we've always said, we don't consider those ones that - where we just did a two- or three-well pad or crude test, and that's why we'll be monitoring the results of these five wells at 500-foot spacing very closely. And we've got another four-well scenario at 500-foot spacing that we'll be doing at Spanish Trail as well.

Okay. And Russell, just to clarify, all of these 500-foot spaced tests that you guys are talking about and the results and the tests you guys have planned, those are all on a non-chevron pattern essentially and more just kind of on the same linear plane? Is that the right way to think about it?

Yes, that's correct.

Okay. Perfect. I appreciate it. And then just wondering on the increased profit and test that you guys have done in the past. I don't think anyone's really haven't heard anything on an update on that for a long time. Are you guys still seeing that similar trajectory in terms of production performance? Or just kind of wondering how the performance on those tests have been tracking lately?

Yeah. You know we did those I think three Wolfcamp B wells that we've increased our total stim size by roughly 40% to 50%. Those continue to track what we've indicated before, where we were seeing on average roughly 10% to 15% improvement in productivity. For a similar increase it can cost. Now the thing that we saw there was that there was a lot of variation in the wells. Some of them were performing roughly in line and then we had one that was probably 50% better than anything else we have seen. So we haven't done any follow-up test in the Wolfcamp B primarily because we've shifted our focus to the Lower Spraberry. We just bought on line, I think actually last night or sometime yesterday, a three well Lower Spraberry pad with the increased profit concentration. So we'll monitor those results and hopefully have some color on that next quarter.

Okay. Appreciate the time and the color. Thanks.

Thank you. And our next question comes from Jason A. Wangler with Wunderlich. Your line is now open.

Hey. Good morning, guys. Was just curious, the third quarter looked like obviously a lot of wells completed. And as you mentioned, the fourth quarter we are going to have a little bit of a holiday. What do you think the steady stage kind of completions would be on a quarterly basis if you could kind of continue that four rig and one completion crew activity level as we look to 2016?

Yeah. I think the fourth quarter probably around 14, 15 completions, something like that. The completion lever is one of the things that we can crack on to control that outspend in 2016 as well. But I think that cadence would be roughly in line for the fourth quarter anyway, 14, 15.

Okay. And just obviously we are almost done with 2015 and haven't put anything on the way of hedges, don't really necessarily need to a year. But, is there any thought of looking at that just to kind of lock in some of the prices to even the Lower two or three rig problem? Or are you just going to kind of let these prices go until we see something better?

Yeah, Jason, we looked this morning for hedges, and I think hedges were still running for 2016 cal just straight swaps somewhere a little less than $52 a barrel, and if you look at the decisions we've made historically, we've positioned the company to not need a lot of hedges. We've got liquidity option in our ownership in Viper Energy Partners, and we've got essentially an undrawn and an unfully tapped borrowing base. So we believe in oil price recovery. We don't believe that our finances have to have hedges, and at $52 a barrel I don't want to lock out my investors from the upside in oil price. So we looked at it just about every day, but right now the risk versus reward we just feel, say, remains unhedged for 2016.

Definitely understand. Appreciate the time. Bye-bye.

Thank you. And our next question comes from Jeb Bachmann of Scotia Howard Weil. Your line is now open.

Morning, everyone. Travis, just a couple quick ones. Going back to earlier this year, you talked about being able to be essentially cash flow neutral to slightly positive in a 50 world in a four rig, and I think you guys have certainly exceeded that, and I was just wondering if that oil price has changed going into 2016 or you guys still think about it in that same situation?

Yeah. Again Jeb, we've not laid out much details for what 2016 is going to look like. We've had a varied rig count this year. We've been up to five and we'll have some carrying expenses in 2016 that will be attributed to a high rig activity. So kind of the things we crank on is completion cadence, well costs, commodity price, and we look at the varying cash outflows or cash out-spins if needed, what gets generated out of that model. If needed, if we get into a real four-star scenario in commodity prices, it could go all the way down to one or two horizontal rigs and maintain all of our lease obligations and be cash flow positive in a couple quarters once we burn off carrying costs from the prior year. So we've got it I think bracketed pretty well, Jeb, and I think in all those scenarios we've got our foot hovering over the accelerator and if we need to mash on the gas when the commodity price improves, which we believe it will, we'll be poised to do so.

Great. And one more, just kind of on the technology front. Just wondering if you guys are employing the CnF technology from FloTek that some of your competitors are on the completion side?

No.

Okay. Great. Appreciate it, guys.

Yeah. Jeb, it's just something we're watching. And one good thing about what goes on in the Permian, especially if there's success from the service companies that provide a service, we'll know about it really quickly. So we're not using it, but we're monitoring it.

All right. Thanks, Travis.

Thank you. And our next comes from Sam Burwell of Canacord Genuity. Your line is now open.

Good morning, guys. Most of my questions have been answered thus far. But I wanted to throw one in on lateral lengths. I mean it seems like the vast majority of your wells are 7,500 feet, but any plans to drill some 10,000 footers going forward?

Yeah. If you look at our average well for this year, it'll be right around 7,000 feet. You'll see that number go up next year. A lot of our Howard County acreage and Glasscock County acreage is laid out nicely to drill 10,000 foot laterals. I don't know the number off the top of my head on how many 10,000 foot laterals we drilled this year, but we drilled quite a few. And operationally, everything seems to be working fine. So we're migrating to longer laterals where we can, depending on how our acreage is laid out.

What percentage of your acreage would you say is amenable to 10,000 foot laterals, rough numbers?

I would say probably 30% to 40%. Our Southwest Martin County acreage, the way it's laid out, it makes sense to do 7,500 foot laterals. And then some of our Northwest Martin, those are laid out in [indiscernible] versus sections, so a lot of those are 8,000 feet. Northeast Andrews County is kind of a mix between 7,500 and 10,000. And the same thing on the east side of the basin. But as we're laying out drilling units, we're trying to lay them out with 10,000 laterals wherever we can, and trying to swap acreage with other operators to make that happen.

Okay. Sounds good. Thanks for the color.

Thank you. And our next question comes from Ryan Oatman of Cowen and Company. Your line is now open.

Hey, guys. This is Brandon for Ryan. A quick, if we could go back to the Middle Spraberry real quick. How much of that acreage has had significant prior vertical development such that you would have concerns about horizontal Middle Spraberry productivity?

If you look at the majority of our Midland County and Southwest Martin County, those have had a lot of vertical well development. But the same thing affected the Lower Spraberry as well. And so we haven't seen a big difference in horizontal well productivity in the areas where we had vertical development versus where we didn't. So we don't think it's a big effect. We just don't think those vertical wells affectively depleted the shale intervals where we're replacing the horizontal laterals. So I think there is some effect there, but it's not a big effect. If you look at where the Middle Spraberry reported results have been, in Martin and Midland, those are areas that had vertical well development. So we think the results are already reflecting that.

Awesome. Great. That is really helpful. Then one more here. You guys have always been focused on high margins, even in the days of $90 oil. Have you guys discussed the need for cost reflect - commodity price with these new wells approaching 5.5 million in oil at 50? Can you help us understand how efficiently you and your partners have gotten in this area? And how do returns look from a historical context? Are they similar with where you were at $70 and $90 oil?

Yeah. Just looking at Russell here. Probably we're about the same as at $70.

Yeah. It was probably about the same as $70 to $80. Even though the costs have come down considerably in that 25% to 35% range as we indicated, but oil is down almost 50%. So you're not seeing the same returns that you did at $90 or $100 oil, but as we indicated in that table, even at $50 oil, we've got a lot of inventory that has pretty nice returns. If you gave us a choice, we'd take the $90 oil back at the higher costs.

Great. That's really helpful. Thanks, guys. That's it from me.

Thank you.

Thank you. [Operator Instructions] And our next question comes from Jeff Robertson of Barclays. Your line is now open.

Thanks. Russell, a question on the Wolfcamp A, as you layer that in where you've already had Wolfcamp B wells and maybe even Lower Spraberry wells, will you complete those wells differently than where you may not have those other two zones above and below that have been developed?

Yeah. I think the one thing we would certainly do is just try to stagger that Wolfcamp A lateral between wherever it would be or Lower Spraberry laterals are. We're not certain that will make a difference, but I think it gives us the best opportunity. And one thing is as we've been testing different things on the completion side in addition to more profit-loading. We're also testing tighter cluster spacing and I think that's probably something that we consider as well just to try to get as much stimulation near the lateral as we can. We don't want to necessarily try to get a lot of frac height growth. You don't have a whole lot of options on limiting that, but we'd also do everything we could on that side to keep the frac within that Wolfcamp A interval.

So that will minimize the chance that you get interference with existing wells?

Yes.

And a question, Tracy, on the DD&A rates, you talked about the impairment effect on lower DD&A. Are you all seeing any significant impact on DD&A from the increased tight curves that you've talked about this year?

We get more reserves, would you say? Sorry. I was referring - looking over here at Russell.

Yeah. I mean there is going to be some effect because we are going to be booking quite a bit more Lower Spraberry PUDs than we had before. If you remember last year, we had a pretty low number of Spraberry PUDs just because we hadn't drilled that many Lower Spraberry wells. So as we look at this year and you look at how many Lower Spraberry wells we completed, we'll have quite a few more PUDs in the Lower Spraberry, so that will affect the DD&A rate...

Which will help.

Yeah. Which will help...

Help the impairment, but what's - what the impair - the impairment is being caused by just that rolling average price that keeps kicking down and down as three months roll off. So the offset of more reserves will help reducing impairment, although we are kind of in a cycle of having to record the impairment here until the prices start to flatten out on the SEC rolling.

Yeah. I mean with the drop in oil prices since last year, that SEC rolling first of month price is still going down. It was almost $72 a barrel at the end of 2Q. At the end of 3Q, it was $59 a barrel, so over about a $12 per barrel drop. And if you look at our projection for what it's going to be at the end of this year, the SEC price will probably be slightly below $51 a barrel, so it's continued to trend down and that's the biggest driver of the impairment. We've been increasing reserves, but our PV10 values have gone down due to pricing.

Okay. Thank you.

Thank you. And our next question comes from Lane French of Robert W. Baird. Your line is now open.

Good morning. I was wondering if you could provide some color on Viper's NGL realizations. It appears that the spread between average might double as your prices compared to your realized NGL prices seem too wide by about $3 per barrel or so over the quarter. I was wondering if there is a specific reason for that, and how to expect that to proceed going forward?

Hi. This is Tracy. So our NGLs actually the pricing is more of an effect of a prior period adjustment on the volumes. We actually had recorded some positive volume PPAs into this quarter due to an under-accrual in Q2. So that's really affecting the price that you're seeing. If you average the three quarters, you're really going to get a true price. Now again, it's very immaterial to our revenues and this PPA is very small and immaterial in the overall scheme of things. That's really where that pricing got a little out of whack there.

Thank you.

Yeah. Just one other comment on that. So we're probably averaging maybe $13 a barrel right now for NGL. One thing that really affects that average NGL price is the amount of Ethane recovery. And the plant that most of Vipers lines were going to was not doing a lot of Ethane rejection, which they have recently started. So there may be a tick-up in the average price, although the NGL volumes will go down as well. So it might be a little better than $13. And you know, typically NGL prices improve in the winter months as well, particularly from a propane side. So I'd expect a tick-up in the next couple of quarters, and hopefully, we're at the beginning of a longer-term recovery in NGL prices.

Thanks.

Thank you. And I'm showing no further questions at this time. I'd like to turn the conference back over to Travis Stice for closing remarks.

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

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. How a great day, everyone.