Viper Energy, Inc. (VNOM) 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 Conference 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, Kandyce. Good morning and welcome to Diamondback Energy and Viper Energy Partners joint third quarter 2015 conference call. During our call today, we’ll reference an updated investor presentation, which can be found on our 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 no 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 sakes. 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 will not accelerate activity until service cost 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 environment warrants consistent with our practice of capital discipline. As illustrated on Slide 5, 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 improved. 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 de-risked on our Spanish Trail and Southwest Martin County acreage. Slide 6 and 7 show Diamondback's completions in the Wolfcamp A and Middle Spraberry as well as those of offset operators. Our first operated triple-stack well was completed in Spanish Trail. The Trailand A unit 3906 Low Spraberry, Wolfcamp A and Wolfcamp B have a combined average 30-day IP of 3,200 Boes a day. The Wolfcamp A well 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 from Midland County of 990,000 Boe and 638,000 Boe 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 861 Boes a day. We are drilling our first four-well stack 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 33,000 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 8 shows that in our primary development areas in Midland, Martin, and Andrews County, Diamondback continues to lead drilling efficiency times 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 begun development in our new Glasscock County area, our first three wells reached TD faster than offset operators. Slide 8 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 LOE is attributed to our continued efforts to implement best practices on acquired acreage, reduced failure rates and optimize costs. Slide 9 shows reductions in LOE since their peak as well as current cost savings to drill complete and equipped a 7,500 foot lateral. We continue to capture incremental savings due to cost concessions and permanent efficiency gains with current well cost down 25% to 35% from last year’s peak. Average drill, complete and equip cost for the year are expected to be between $6.2 million and $6.4 million for 7,500 foot lateral as leading edge well cost 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 strength 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 productions and lower cost, 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 range of $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 peer average by over 30% while on Slide 8 we show that year-to-date operating expenses were 17% lower than the peer 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 peer 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 re-determination, 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 time. Viper has no minimum quarterly distribution or complex ownership hierarchy. The majority of cash flow is returned to unitholders through quarterly distribution 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 Boe to 5,200 Boe/day, up from prior guidance from 4,800 Boe/day to 5,100 Boe/day. As a reminder, Viper does not incur LOE or capital expenditures. We've also lowered Viper DD&A guidance for 2015 to a range of $17 to $19/Boe from $20 to $22/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 of 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 the extend 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 for my stockholders to expect our fingerprints are on every transaction that occurs out here in the Permian because, as I've said before, you're 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 and as well as the larger deals. In terms of capacity, we don’t typically screens on deals by on how big they could be, we look at the quality of the lot. And then we believe that we identify high quality lots that our investors will appreciate our execution prowess and our financial performance and 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 very helpful. And I wanted to switch over to Slide 5. I was hoping you could maybe speak to how reallocation in Slide 5 does the scenario analysis in different commodity crisis. I was hoping you can maybe speak to how reallocation between the different operating areas might look in different scenarios?

Yes, we've consistently said that 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 Viper has and Diamondback own 98% of Viper. So we'll always try to keep two rigs at any commodity price in Spanish Trail. And then as you look for us 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 and do some drilling in Northwest Martin County or Northeast Andrews County.

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

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

Okay, that’s very helpful. Thanks again and congratulations on the quarter.

Thanks, John. I guess just to close that thought out, as you get the higher oil prices $65 to $75 oil we probably allocate a rig back down in Hudson County.

Thank you. And our next question comes from Dave Kistler of Simmons & Company. Your line is 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-on in and around mostly Midland County acreage and, yes, there is a portion of that acreage that Viper has owns the mineral, so those accretive on both fronts, both Viper and Diamondback. And it really underscores our continued effort 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 executing the rock on just about any deal size but the blocking and tackling that is required to do these bolt-on deals is kind of the day in and day out activity.

I appreciate that. And then also kind of thinking about Slide 5, but more so trying to tie it to a 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 do you've outlined the rigs?

Yes, Dave, that is a good rule of thumb and just to clarify that, that would also include drill, complete, equip and any associated facilities and infrastructure that would have to do, so somewhere in that $100 million range per rig.

Absolutely. And then just 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 what not. Is that the metric you need as you ratchet up in each one of these or is this really a PV-10 analysis?

It’s more of a PV-10 analysis, Dave, just to give our investors a full scale look at the inventories that we have in our control.

Okay. Appreciate that, and 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 in with within, if you’re going to outspend cash flow little bit or is mandate largely live within cash flow with the exception of maybe acquisitions et cetera?

Yes, good question, Dave. It’s actually about four of those things you just layered -- laid out there. We consider -- in our capital allocation process, we consider no 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. But we try to maintain typically below 50% drawn on that 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. And so it’s not just a single metric we look at but it’s really a combination of all of those that I have just mentioned and with our stated objective of rate of returns back to our shareholders we try to allocate capital accordingly.

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

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

Perfect, I really appreciate all the added color and thanks for letting me making so many questions. Thank you.

You bet, Dave. Thank you.

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

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

Yes, Mark, the Wolfcamp A results we thought turned out really well based on our results and those of rather 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 about the Wolfcamp A is in Howard County. So I think as you look at our focus going out in 2016, obviously, the Lower Spraberry will still be the main focus but I think you will see more Wolfcamp A wells come in to the mix. On the Middle Spraberry, as we had 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 we move to the east and I think you see that in the results of some other operators as well. So kind of on that eastern side of Midland County, I think you’ll see a few more Middle Spraberry wells come in to the mix as we continue to test the zone on some of the other items.

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

Yes, I think we are 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 see us continue to delineate some of the other zones and maybe that percentage of Lower Spraberry wells would move down a little.

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

Yes, I think it’s probably a still little early. We had reported some results off of two and three-well pads based at 500 feet. We just recently completed five wells essentially developed half of section at 500 foot spacing; the last of those wells are just recently come online, so it’s still a little early to gauge the results there. Some of the earlier wells were watered out and they've come back nicely. So I think with the data we’ve got so far, we are comfortable in saying that on average we’re meeting or maybe slightly exceeding that Ryder Scott type curve. We do have some 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 will be into 1Q or 2Q before we had some results there on 500 foot spacing. We we're kind of doing some 660 foot spacing test in Northwest Martin but again while looking at 2Q before we have some meaningful results there.

Got you, thanks, Russell.

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

Good morning guys.

Hi Neal.

You or Russ, one of the guys, obviously just when you think you cannot squeeze out anymore cost I mean pretty impressive that $5.5 million to $5.8 million along with the nine days, your thoughts on are you still will be able 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 pretty incredible, I think you can get anything under that?

We’re going to - first off on the service cost side, the service sector has responded in a pretty fulsome way in 2015 with cost concessions. I still maintain it as long as there is idle equipment in the yard there is pressure from the service sector guys to put that on to work which means they have to come down on cost. I can tell you probably for just planning purposes it feels like this is sort of the bottom; we may move marginally down, if commodity prices continue to soften or really even stay where they are right now, but I think just for planning purposes it still feels like a 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 the 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 in making permanent some of these cost savings through the efficiency gains we made but we’re always going to continue to try to push that envelope.

You said about the service, I think but either the rigs on the frac side would anybody let you lock in to 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 cost than what we’re going to see for a longer period of time. So I believe that we are getting extremely good service, extremely competitive pricing right now, and for Diamondback I believe we’re just going to -- we’re going to play the low cost guys that are delivering really good service right now for the near future.

Got it. And then just lastly, I know with what you have in Viper and stuff it just makes sense for the minerals to drill in that core area and said you are in Howard, what about your Southern acreage? Any thoughts of doing some things down there anytime down and up to anytime soon?

Yes, I think I was kind of addressing that little early to one of the questions when I said because I can’t forget about Hudson County. Hudson County is going to need probably $65, $70 oil before we would allocate capital down there. 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 the $65 to $70 range.

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

Travis, I like the scenario analysis in Slide 5 and it looks like you've kind of already on hid a couple of columns here on the CapEx and capital allocation front. I was hoping you can maybe unhide the growth column here, and just curious on what the associated growth is with each one of these scenarios; you've already kind of hinted that you're flattish in two to three rigs. Maybe you can talk about $45 to $55 and 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 still got some decisions we have to make on which well pipes we're going to drill, whether we drill them 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, 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 your updated full year guidance looks like implies a sequential decline going into next quarter. And just wanted to get some color on some of variables in Q4, whether you're implying that you're going to build ducks or you've got some pair drilling, just few things that could be going on there, wanted to get some color, thanks.

Sure, Mike. Well, yes, you're right in the fact that we're probably with one completion crew and four drilling rigs, we're going to be building ducks 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 on the, and you have to take the upper end of our production range guidance, you're going to see that relative to where we are right it's close to the flat quarter-over-quarter expectation. I don’t know exactly that’s going to be play out that way because there's also some things that typically occur in the fourth quarter we're trying to take into account. One specifically is that we never can count on weather but we know that there's usually a weather event somewhere in the 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 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 and 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, but I know we've only got eight weeks or so left in the year, but those are the things we're considering.

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

Thanks. Good morning, everybody. My question, and we talked about this a little bit last night but my question had to do with the development configuration as you kind of play your 2016 program specifically regarding the kind of stacked-well development configuration. And I guess my question do you notice any differences on the productivity side of the equation by doing a pad on a stacked-well configuration across the various benches versus just focusing in one bench? So first on the productivity side. And 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?

Yes, I’ll answer the second question first. There's really no efficiency difference whether you drill three-stack 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 basis, it may be more toward two-drill stack laterals because of the relative absence of frac beds between the units. And so, our plans have always been to start out drilling stack laterals on the east side of the basin, Howard and Glasscock Counties. And as you can see from our press releases we've tested some stack laterals on the west side of the basin and we got a four-well stack we drilled in that Southwest Martin County acreage and we're actually going to frac too the inner wells first the Wolfcamp B and Lower Spraberry and then back about a month later and frac the Wolfcamp A and Middle Spraberry, and we'll tag those fracs and monitor the results. We'll try to get a better gauge of how much communication we're seeing vertically between those. And so based on attempts like those hopefully we'll make the best decision going forward but if you ask us right we'd probably still lean towards for the most part drilling same zone on the western side of the basin and stack 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. Wanted to kind of get your thoughts on some recent activity we’re seeing in industry with your neighbors in Spanish Trail get some good 500 foot Lower Spraberry results in the same landing zone. Just kind of wondering how you guys are viewing prospectivity of a concept like that and then just kind of generally your interest in any sort of operator test of a similar concept?

While as we know I mean we just talked about the -- we drilled those five wells across 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’ve made decent test 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 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 results of all the wells drilled at 500 foot spacing versus the ones drilled at 600 foot or 660 foot spacing versus what we’ve called singular wells which are wells that don’t have an offset well within say within 1,300 feet. And I mean if you look at that, you don’t see really any material difference between the ones that are in 500 versus 660 but as we've always said, we don’t consider those ones that where we just did it two or three-well pad or true test and that’s why we will be monitoring the results of these five wells at 500 foot spacing very closely. And we’ve got another four-well scenario it 500 foot spacing that we will be doing at Spanish Trail as well.

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

Yes, that’s correct.

Okay, perfect color, I appreciate it. And then just wondering on the increased probing test that you guys have done in the past, I don’t think anyone is really heard anything on an update on that front, I mean are you guys still seeing kind of that similar trajectory in terms of production performance, just kind of wondering how the performance on those test have been tracking lately?

Yes, we did those I think three Wolfcamp B wells that we increased our total stem size by roughly 40%, 50%. Those continue to track what we had indicated before what we were seeing on average roughly 10% to maybe 15% improvement in productivity for a similar increase in cost. Now the thing we saw there was a lot of variation in the wells, some are more performing roughly in line and then we had one that was probably 50% better than anything else we had seen. So we haven’t done any follow-up test in the Wolfcamp B primarily because we kind of shifted our focus to the Lower Spraberry. We just brought online I think actually last night or sometime yesterday a three-well Lower Spraberry pad with the increased profit concentration. So we will monitor those results and hopefully add some color on that next quarter.

Okay, I appreciate the time and the color, Thanks.

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

Hey, good morning, guys. Was just curious the third quarter looks like obviously a lot of wells completed and as you mentioned kind of fourth quarter we’re going to have a little bit of holiday, what do you think the steady-state kind of completions would be on a quarterly basis if you could kind of continue that four rig and once completion crew activity level as we look at 2016?

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

Okay. And just obviously we’re almost done with 2015 and haven’t put anything on the way hedges don’t really necessarily need to either, 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 program are you just going to kind of let these prices go until we see some better?

Yes, Jason, we looked this morning for hedges and our hedges are still running for 2016 cal grade swaps somewhere little less than $52 a barrel. And if you look at the decision we 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 non-fully 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 prices. So we look at it just about every day but right now the risk versus reward we still say remains unhedged for 2016.

Definitely understand it, I appreciate the time.

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

Good morning everyone. Travis, just a couple of quick ones. Going back to early this year you talked about being able to be essentially cash flow neutral to slightly positive in the $50 world and a four rig and I know you guys have certainly exceeded that. I’m just wondering if that oil price has changed going into 2016 or are you guys still thinking about it in that same situation?

Yes, again Jeb, we’ve not laid out much details for what 2016 is going to look like. We had a varying rig count this year, we have been up to five and we will have some carrying expenses in 2016 that will be attributed to high rig activities. So kind of the things we crank on is completion cadence, well cost, commodity price and we’re looking to varying cash outflows or cash outspend if needed or what gets generated out of that model. If needed if we get into real four star scenario of commodity prices it’s all the way down to one or two horizontal rigs and maintain all the lease obligations and be cash flow positive in the couple of quarters once we burn off carrying cost from the prior year. So we’ve gotten I think bracketed pretty well, Jeb, and I think in all those scenarios we have got our foot covering over the accelerator, and if we need to match on gas if commodity prices improves, which we believe it will, we will be poised to do so.

Great. And one more just kind of on the technology front, just wondering if you guys are employing the C&F technology for Flowtec that some of your competitors are on the completion side?

No.

Okay, Great. I appreciate it guys.

Yes, Jeb, it’s just something that we’re watching. One good thing about what goes on in the Permian especially if there is success from the service companies that provide a service, we will know about it really quickly. So, we’re not using it but we’re monitoring it.

Thanks Travis.

Thank you. The next question comes from Sam Burwell of Canaccord 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 x, I mean it seems like the vast majority of your wells is 7,500 feet, is there any plans to drill some 10,000 footers going forward?

Yes, I think if you look at our average well for this year it will 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 on top of my head on how many 10,000 foot laterals we drilled this year, but we’ve drilled quite a few and operationally everything seems to be working fine. So we’re migrating the 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 here and in some of our Northwest Martin those are laid out in the board versus section. So lot of those are 8,000 feet. Northeast Andrews County is kind of a mix between 7,500 and 10,000 and same thing on the east side of the basin. But as we’re laying out drilling units we’re kind of laying out units with 10,000 foot 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. Quick if we could go back to the Middle Spraberry real quick, how much of that acreage has that significant prior vertical development such that you would have concerns about horizontal Middle Spraberry productivity?

If you look at our majority of our Midland County and Southwest Martin County those have had a lot of vertical well developments, but that 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 effectively depleted the shale intervals where we’re pricing the horizontal laterals. So I think there is some effect there but it’s a not a big effect. And if you look at where the Middle Spraberry reported results have been in Martin and Midland, those are areas that they had vertical well development. So we think that the results are already reflecting that.

Awesome, great. That is really helpful. And 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 current commodity price with these new wells approaching $5.5 million and 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?

Yes just looking at, Russell here, and probably we are about the same as $70 dollar.

Yes. We’re probably about the same as $70 to $80 even though cost have come down considerably in that 25% to 35% range as we indicated but oil is down almost 50%. So if you’re not seeing the same returns that you do $90 or $100 but as we indicated in that table even if $50 oil we got a lot of inventory that has pretty nice returns. If you gave us a choice we take the $90 oil at higher cost.

Great, that’s really helpful, thanks guys. That’s it for 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 laid that in where you already have Wolfcamp B wells maybe even Lower Spraberry wells, will you complete these wells differently than where you may not have those other two zones above and below that have been developed?

Yes, I mean I think the one thing we would certainly do is try to stagger that Wolfcamp A lateral between where B or Lower Spraberry laterals are. We’re not certain that 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 proppant loading, we’re also testing tied or 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 necessary try to give a lot of product type growth, you don’t have a whole lot options on limiting that, but we 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 type curves that you talked about this year?

I‘m sorry, I was referring looking over here at Russell.

Yes, I mean there is going to be some effect because we’re going to be booking quite a bit more Lower Spraberry PUDs than we had before, you can remember last year we had a pretty low number of Lower Spraberry PUDs just because we haven’t drilled that many Lower Spraberry wells. So as we look at this year and you look at how many wells, 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.

Yes, which will help.

Help the impairment but with the impairments being caused by the rolling average price that, that keeps sticking down and down as three months roll off. So the offset of more reserves will help reduce any 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.

Yes, I mean with the drop in oil price 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 $12 per barrel drop, and if you look at projection for what is going to be at the end of this year, the SEC price will be probably 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 PV-10 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 Mont Belvieu NGL prices compared to your realized NGL prices seem to widen by about $3 a barrel or so over the quarter. I was wondering if there's 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 prior period adjustment on the volume. We actually had recorded some positive volume PPA into this quarter due to an under accrual in 2Q. 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. But that’s really what our pricing got a little out of whack there.

Thank you.

Yes, just one other comment on that. So we’re probably averaging may be $13 a barrel right now for NGLs. One thing that really affects that average NGL price is the amount of ethane recovery and the plant that most of Viper’s volumes 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 volume will go down as well. So it might be a little better than 2013 and typically NGL prices improves during the winter months as well particularly on the propane side. So I’d expect to tick up next the couple of quarters and hopefully we will - 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 again to everyone 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. Have a great day everyone.