Diamondback Energy Inc (FANG) 2015 Q3 法說會逐字稿

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, today's 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 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 reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.

I will now turn the call over to Travis Stice.

Thank you, 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 have 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 would 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 the environment warrants, consistent with our practice of capital discipline.

As illustrated on slide 5, we have 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 Diamondbacks 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 de-risked on our Spanish trail and Southwest Martin County acreage. Slides 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 stacked well was completed in Spanish Trail. The Trailand A Unit 3906 Spraberry, Wolfcamp A and Wolfcamp B have a combined average 30 day IP of 3200 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 for Midland County of 990,000 BOE 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 2 string, 30 day IP of 851 BOEs a day.

We're 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 BOE to 32,000 BOE a day, up from 30,000 BOE to 32,000 BOE 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 9 days. I am proud that as we have 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 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, reduce failure rates and optimize costs.

Slide 9 shows reductions 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 a 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 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 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 Diamondbacks DD&A guidance to a 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 effect of hedges was $47.

Diamondback continues to have peer-leading cash margins 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 acquisitions. During the third quarter of 2015, Diamondback achieved positive free cash flow for the second time in company history, excluding acquisitions.

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 unitholders 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 to19 per BOE from 20 to 22 per BOE previously. This is due to an increase in its reserves.

I will 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 are poised to accelerate when price recovers.

Before we turn the call over to Q&A, want to recognize each of our 139 employees for all the hard work they have done to continue our track record of execution in 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.

(Operator Instructions)

John Nelson, Goldman Sachs.

Good morning, and congratulations on a very strong quarter. I think, after the August equity raise, a lot of us were expecting an acquisition announcement was probably looming. I am sure to what extent you're limited in talking, but can you talk 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?

John, that is a good question, and you know my track record is, we typically do not talk about any acquisitions that are currently ongoing. But I can tell you, with regards to the pipeline, we still continue to see good opportunities out there.

I will 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 is reasonable for my stockholders to expect our fingerprints are on every transaction that occurs out here in the Permian, because, as I have said before, you are either in that M&A game, or you are 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 then, we believe 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. We really don't filter the deals on how big or how large they could be.

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

We have 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 owning 88% of Viper, so we will 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 will have the two rigs in Spanish Trail and we will have two rigs, both -- one rig in Howard, one rig in Glasscock County -- and then we will bounce between those two new development areas into some drilling in Northwest Martin County or Northeast Andrews County.

Would a fifth rig be added, then, back to -- which area as we stepped up that chain?

As you start moving up, we have 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 would 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's very helpful. Thanks, again, and congratulations on the quarter.

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

Dave Kistler, Simmons & Company.

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?

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's a portion of that acreage that Viper has the -- owns the minerals, so it was accretive on both fronts, both Viper and Diamondback. And it really underscores our continued effort to build our high-quality inventory, where we are 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 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 a day-in and day-out activity.

Appreciate that. And then, also thinking about slide 5, but more so trying to tie it to a capital program. If we look at this year and back into the numbers, it feels like about $100 million of CapEx in aggregate equals 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?

Yes, Dave, that is a good rule of thumb. And just to clarify, that would also include drill, complete, equip, and any associated facilities and infrastructure that we would 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 have highlighted in your portfolio before that returns are 40% to 70% at $40 oil and, obviously, Spanish trail and whatnot. Is that the metric you need as you ratchet up in each one of these, or is this really PV-10 analysis?

It is 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 are focused on in terms of, maybe a debt to EBITDA leverage ratio that you would want to stay within, if you are 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 2 times debt to EBITDA. We also look at our borrowing base, and as Tracy outlined, we conservatively took only $500 million out of a $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. So, we try to mix all of those together along with lease obligations and drilling obligations and come up with an allocation process. And so, it is not just a single metric we look at, but it is really a combination of all of them -- all of those that I just mentioned. And with our stated objective of rate of returns back to our shareholders, we try to allocate capital accordingly.

Appreciate that. And one last one, if I can sneak it in. Looking at the growth you have delivered year to date, if you taper down to a two- or three-rig program, would that be considered maintenance CapEx and put you toward a flat production or would that be 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 are at two to three rigs, yes, I would expect more of a flattish production profile for next year.

Perfect. I really appreciate all the color, and thanks for letting me sneak in so many questions. Take care.

Mark Lear, Credit Suisse.

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.

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 it seems to be outperforming the Wolfcamp B in this area. And, of course, we've always talked about how good we think the Wolfcamp A is in Howard County.

I think, as you look at our focus, going out in 2016, obviously the Lower Spraberry would still be the main focus, but I think you will see more Wolfcamp A wells come into the mix.

On the Middle Spraberry -- as we have 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 result of some other operators as well. So, kind of on the eastern side of Midland County, I think, you will see a few more Middle Spraberry wells come into the mix as we continue to test that zone on some of the other acreage.

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?

I think we're probably still looking at something on the order of 60% of the Lower Spraberry wells. I think in a real low price environment, that number could move up, if oil prices improve. I think you would 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 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 are currently working on.

I think it is 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 500-foot spacing. The last of those wells have just recently come online, so it is 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 have got so far, we are comfortable in saying that, on average, we are meeting or maybe slightly exceeding that Ryder Scott type curve.

We do have some -- an additional 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 have some results there on 500-foot spacing. We are doing some 660-foot spacing test in Northwest Martin, but, again, probably looking at 2Q before we have some meaningful results there.

Got you. Thanks, Russell.

Neal Dingmann, SunTrust.

For you, Russ, or one of the guys. Obviously, when you think you can't really squeeze out any more cost, pretty impressive that 5.5 to 5.8 along with the nine days, your thoughts on, are you still be able to put some pressure on the service companies out there? And, secondly, on these efficiencies, can you really get anything down -- nine days seems pretty incredible. Can get anything under that?

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 that, as long as there is idle equipment in the yard, there is pressure from the service sector guys to put that iron 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 at right now. But I think just for planning purposes, it sort of feels like a bottom.

In terms of the efficiency gains, I am really proud of the organization that they continue to do more, almost on a quarter basis. And I know we have 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. I do think that we have made some great strides this year in making permanent some of these cost savings through the efficiency gains we have made, but we are always going to continue to try to push that envelope.

Given what you said about the service -- or anybody, either the rig side or frac side, would anybody let you lock into longer-term deals around these levels?

We have 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 at extremely competitive pricing right now. And, for Diamondback, I believe 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, with what you have in Viper and stuff, it just makes sense with your minerals to drill in that core area, and I know how excited you are on Howard. What about your southern acreage? Any thoughts of doing some things down there any time -- down in Upton any time soon?

I think I was addressing that a little earlier in one of the questions when I said -- because I forgot about Upton County. Upton County is going to need probably $65, $70 oil before we would allocate capital down there. That was our original development area, and we are 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. Great quarter, Travis.

Mike Kelly, Seaport Global.

Travis, I like the scenario analysis on slide 5. It looks like you have already un-hid a couple columns here on the CapEx and capital allocation front. I was hoping you could, maybe, unhide the growth column here, and just curious on what the growth -- what the associated growth is with each one of these scenarios. You already hinted that you are flattish at two to three rigs, maybe you could talk about the $45 to $55 and the $55 to $65.

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. We've still got some decisions we have to make on which well types we're going to drill, whether we drill them stacked laterals, or we drill all one zone. And we have got to see what the commodity price is going to do as we exit the year. I promise you, when it is time to talk about 2016, I will -- as you pointed out, I will unhide the columns, and we will give you all the details that you need to put your model together, but still premature right now.

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

Mike, you're right in the fact that we will 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 will build a couple as we exit this year, as well. There's a couple of other macro events that go on. But, first, if you just do the math on -- 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 is close to flat quarter-over-quarter expectations.

I don't know exactly if it's going to play out that way, because there is also some things that typically occur 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 is usually a weather event somewhere end of 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, so our utilization rates during the fourth quarter typically drop a little bit.

So we try to take all of that into account. And, again, we have never guided towards the quarter's production volumes because of some of those things that we just outlined. But I know we have only got eight weeks, or so, left in the year, but those are things we are considering.

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

Gordon Douthat, Wells Fargo.

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. My question is, 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? 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?

I will answer the second question first. There really is 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.

Our plans have always been to start out drilling stacked laterals on the east side of the basin -- Howard and Glasscock Counties. And, as you can see from our press releases, we have tested some stacked laterals on the west side of the basin, and we have 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 will tag those fracs and monitor the results to try to get a better gauge of how much communication we are seeing vertically between those zones.

Based on tests like those, hopefully we will make the best decision going forward. But if you ask us right now, we probably still lean towards, for the most part, drilling the 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.

Jeff Grampp, Northland Securities.

Wanted to get your thoughts on some recent activity we have seen in industry with your neighbors in Spanish Trail getting 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 general your interest in any operated test of a similar concept.

As you know, we just talked about, 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, so we will 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 have had several other tests, as well, where we have done a two-well pad or three-well pad at 500-foot spacing. I think we show the general results of those. I think it is one of the slides in the Appendix, actually. I think it is slide 18 where we show the average result of all of the wells drilled at 500-foot spacing versus the ones drilled at 600 foot -- or 660-foot spacing versus what we called singular wells, which are wells that don't have an offset well within 1,300 feet. If you look at that, you don't see really any material difference between the ones that are at 500 versus 660, but as we've always said, we don't consider those ones at where we just did a two- or three-well pad a true test. And that is why we will be monitoring the results of these five wells at 500-foot spacing very closely. And we have got another four-well scenario at 500-foot spacing that we would be doing in Spanish Trail as well.

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

Yes, that is correct.

Okay. Perfect. I appreciate it. And then, just wondering on the increased proppant test that you guys have done in the past, I don't think anyone has really -- I haven't heard anything on an update on that front. Are you still seeing that similar trajectory in terms of production performance? Or just wondering how the performance on those tests have been tracking lately.

We did those, I think, three Wolfcamp B wells that we increased in our total stem size by roughly 40% to 50%. Those continue to track what we'd indicated before where we were seeing, on average, a roughly 10% to 15% improvement in productivity for a similar increase in cost. The thing 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 had seen.

We haven't done any follow-up tests in the Wolfcamp B, primarily because we have shifted our focus to the Lower Spraberry. We just brought online -- I think, actually last night, or some time yesterday -- a three-well Lower Spraberry pad with the increased profit concentration. So we will monitor those results and hopefully have some color on that next quarter.

Okay. Appreciate the time and the color. Thanks.

Jason Wangler, Wunderlich.

Was just curious, the third quarter looked like, obviously, a lot of wells completed, and as you mentioned fourth quarter, we're going to have a little bit of a holiday. What do you think the steady-state completions would be on, a quarterly basis, if you continue that four-rig and one completion crew activity level as we look at 2016?

I think the fourth quarter, probably around 14 or 15 completions, something like that. The completion lever is one of the things that we can crank 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. Obviously, we're almost done with 2015 and haven't put anything on the way of hedges -- don't really necessarily need to, either -- but is there any thought of looking at that, just to lock in some of the prices, to even the lower two- or three-rig program, or are you going to let these prices go until we see something better?

Jason, we looked this morning for hedges, and I think hedges are still running for 2016, (inaudible) just straight swaps, somewhere a little less than $52 a barrel. 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 have got, essentially, an undrawn and an unfully tapped borrowing base.

We believe in oil price recovery. We don't believe that our finances have to have hedges, and, at $52 per barrel, I don't want to lock out my investors from the upside in oil price. We look at it just about every day, but right now, the risk versus reward, we still say, remains unhedged for 2016.

Definitely understand. Appreciate it.

Jeb Bachmann, Howard Weil.

Travis, 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 and a four rig, and I think you guys have certainly exceeded that. I'm just wondering if that oil price has changed going into 2016. Are you guys still thinking about it in that same situation?

Again, Jeb, we have not laid out much details for what 2016 is going to look like. We have had a varying rig count this year. We've been up to five, and we will have some carrying expenses in 2016 that will be attributed to high-rig activity. The things we crank on is completion cadence, well costs, commodity price, and we look at the varying cash outflows -- or cash outspends, if needed -- or what gets generated out of that model. If needed, if we get into real [sportster] scenario and 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 of quarters once we burn off carrying cost from a prior year.

We have got it, I think, bracketed pretty well, Jeb. And, I think, in all of those scenarios, we have got our foot hovering over the accelerator, and if we need to mash on the gas when commodity price improves, which we believe it will, we will be poised to do so.

Great. And then, one more, 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.

Jeb, it is just something we're watching. And 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 are monitoring it.

All right. Thanks, Travis.

Sam Burwell, Canaccord Genuity.

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

I think if you look at our average well for this year, it will be right around 7,000 feet. You will 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 the number off the top of my head on how many 10,000-foot laterals we've drilled this year, but we have drilled quite a few, and operationally everything seems to be working fine. We are 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 [labors] versus sections, so a lot of those are 8,000 feet. Northeast Andrews County is a mix between 7,500 and 10,000. Same thing on the east side of the basin. But as we are laying out drilling units, we are trying to lay them 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.

Ryan Oatman, Cowen and Company.

This is Brandon for Ryan. 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, 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. We don't think it is a big effect. We just don't think those vertical wells effectively depleted the shale intervals where we are placing the horizontal lateral.

I think there is some effect there, but it is 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 have had vertical well development. So we think 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 costs to 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?

I'm just looking at Russell, here, and probably we are about the same as at $70.

It is probably about the same as $70 to $80. Even though costs have come down considerably in that 25% to 35% range, as we indicated, but oil is down almost 50%. 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 have got a lot of inventory that has pretty nice returns. If you gave us a choice, we would take the $90 oil back at the higher cost.

(Laughter). Great. That's really helpful. Thanks, guys. That's it for me.

(Operator Instructions)

Jeff Robertson, Barclays.

Russell, a question on the Wolfcamp A, as you lay that in, where you already have 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?

I think the one thing we would certainly do is try to stagger that Wolfcamp A lateral between wherever the B or Lower Spraberry laterals are. We're not certain that will make a difference, but I think it gives us the best opportunity.

One thing, as we have been testing different things on the completion side, in addition to more proppant loading, we're also testing tighter cluster spacing, and I think that is 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 heighth growth. You don't have a whole lot of options on limiting that, but we'd obviously 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've talked about this year?

I'm sorry, I was looking over here at Russell.

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. As we look at this year, and you look at how many Lower Spraberry wells we completed, we will 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.

It will help the impairment, but what the impairment -- the impairment is being caused by that rolling average price that keeps ticking down and down as three months roll off. The offset of more reserves will help reduce any impairment, although we are in a cycle of having to record the impairment here, until the prices start to flatten out on the SEC rolling.

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 a $12 per barrel drop.

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. It's continued to trend down, and that is the biggest driver of the impairment. We have been increasing reserves, but our PV-10 days have gone down due to pricing.

Okay. Thank you.

Lane French, Robert W. Baird.

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

This is Tracy. 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 2Q, so that is really affecting the price that you are seeing. If you average the three quarters, you are really going to get a true price. Again, it is very immaterial to our revenues, and this PPA is very small and immaterial in the overall scheme of things. But that is really where that pricing got a little out of whack there.

Just one other comment on that. We are probably averaging maybe $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 volumes will go down, as well.

It might be a little better than $13. And, typically, NGL prices improve during the winter months, as well, particularly on the propane side. So I would expect a tick-up the next couple of quarters, and hopefully we're at the beginning of a longer-term recovery in NGL prices.

Thanks.

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.