Diamondback Energy, Inc. (FANG) Q4 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and welcome to the Diamondback Energy and Viper Energy Partners Fourth Quarter 2014 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to introduce your host for today’s conference Mr. Adam Lawlis of Investor Relations. Sir, you may begin.

Thank you. Good morning and welcome to Diamondback Energy and Viper Energy Partners joint fourth quarter and year end 2014 conference call. During our call today, we will reference an updated investor presentation which can be found on Diamondback’s website. We also posted an investor presentation for Viper on its website. Representing Diamondback today are Travis Stice, CEO; Tracy Dick, CFO as well as other members of our exec 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 on the company’s filings with the SEC. I will now turn the call over to Travis Stice.

Thank you, Adam. Welcome everyone and thank you all for listening to Diamondback’s and Viper Energy Partners fourth quarter 2014 conference call. Last month, in our operations update, we announced fourth quarter production, 2015 guidance and encouraging Lower Spraberry results. Last night, we announced additional encouraging Lower Spraberry results, including our first 500-foot interlateral downspacing test, which is performing in line with the nearby three-well pad on 660-foot spacing. We believe our second Lower Spraberry test in Andrews County and our first test in Dawson County confirmed the strength of the Spraberry formation across the majority of our acreage. As a result of continued strong Lower Spraberry well results, Ryder Scott has increased our PUD reserve levels for a 7,500-foot lateral in Midland County to 990,000 BOE equivalent on a two-stream basis from 650,000 BOE previously. Considering that we built Diamondback Energy on the back of the Wolfcamp B shale, it’s really exciting to embark on yet another development horizon, which appears to be materially better than the Wolfcamp B. We also reported reserves in which we showed proved reserves increasing year-over-year by 77%, up to 113 million barrels of oil equivalent at an associated drill bit finding and development cost of $11.09 per barrel. Proved developed reserves increased 122% over last year to 66.5 million barrels. Additionally, last month, we strengthened our already strong balance sheet by issuing equity. Pro forma for the proceeds from the equity raise, our net debt to annualized 4Q ‘14 EBITDA now sits at 1.2 times. Now, turning to the company presentation Adam referred to. In Slide 4, we depict how at $50 per barrel WTI Lower Spraberry rates of return in Spanish Trail range from approximately 50% to 125% based on the new Ryder Scott estimate of nearly 1 million barrels of oil equivalent for 7,500-foot lateral. Our Spanish Trail Lower Spraberry wells have a breakeven price below $30 a barrel. 65% to 75% of our drilling activity in Spanish Trail this year will target the Lower Spraberry. On Slide 5, we have provided more detailed information on our type curve expectations across our acreage base. Note that several wells, although early on in their production, are outperforming the Ryder Scott type curve. On Slide 7, we show our historical reserve growth. Since 2012, reserves have increased 181%. F&D costs have decreased to $11.09 per barrel during 2014 from $14.46 per barrel in 2013. This is a reduction in F&D of almost 25% reflecting the early promising results, the Lower Spraberry booked at higher EUR per well than last year. As depicted in Slide 9 Diamondback continues to have higher cash margins and lower operating expense metrics than our Permian peers. We are a lean organization and expect to continue optimizing our costs. Our full year ‘14 LOE per barrel was $7.79 which was above guidance of $6 to $7 per barrel. This was due to the nearly 300 vertical wells acquired during 2014 on leases which had substantially higher operating costs. If you strip out the acquired properties, full year 2014 LOE would have been $6.87 per barrel within the guided range. This past quarter was the first to have the full impact from the properties that closed in September. We are working hard to apply our low cost efficient practices on these properties and expect to average between $6.50 and $7.50 per barrel in 2015. Slide 10 shows how our vertical wells and LOE per barrel have changed since the fourth quarter of 2012. In 2013 we decreased LOE from $11.39 to $6.04 in the fourth quarter as we increased the amount of horizontal wells drilled and drove costs lower. We are confident we can replicate this success and expect to see cost savings from reductions in well failure rates and other LOE spend categories. As mentioned in our interim operations update, our focus this year is on capital discipline, stockholder returns and maintaining a strong balance sheet. As previously reported, we are in the process of dropping two horizontal rigs this month and have already released our remaining vertical rig. In 2015 we expect to run three horizontal rigs, including two in Spanish Trail where Viper owns the underlying minerals. Slide 12 shows how the Permian rig count and WTI prices have changed since 2001. Since the beginning of 2015 Permian operators have dropped approximately 140 rigs. Cost concessions are responding to the lower commodity environment. And we are currently seeing approximately 10% to 15% overall reductions. Frac spreads have been slow to respond due to the backlog of completions, but we are beginning to see them react as well. Of our nearly 1,650 net potential horizontal locations of inventory shown in Slide 16, less than 4% are currently booked as PUDs. Assuming the midpoint of the EUR ranges, we have over 800 million barrels of resource potential remaining based on that locations in our inventory. With these comments now complete, I will turn the call over to Tracy.

Thank you, Travis. Diamondback’s net income for the quarter was $98.7 million or $1.74 per diluted share. After adjusting our fourth quarter earnings for non-cash mark to market derivative gains of $111.5 million and netting out the related income tax effect, our adjusted net income was $27.3 million or $0.48 per diluted share. Diamondback’s adjusted EBITDA for the quarter was $111.7 million. Our average realized price for the fourth quarter was $55.60 per BOE and due to the positive impact and our hedge position, our average realized price including the effect of hedges was $62.63 per BOE. We laid out the details of our current hedge position in last night’s earnings release and on Slide 19 of the presentation. In 2015 we have nearly 11,000 barrel a day of oil hedged with swaps at an average price of approximately $88 per barrel. Turning to costs, our LOE was $7.79 per BOE for the full year. As Travis mentioned fourth quarter was the first quarter with the full effect of both acquisitions. Excluding the effect of the acquisitions LOE for the year would have been $6.87 per BOE within our guidance range. Our general and administrative costs came in at $2.65 per BOE for the fourth quarter. This includes non-cash equity based compensation, excluding equity comp G&A is $1.02 per BOE. In the fourth quarter of 2014 Diamondback generated $104.4 million of operating cash flow and $106.8 million of discretionary cash flow or $1.83 and $1.87 per diluted share respectively. During 2014 we spent approximately $487 million for drilling, completion and infrastructure. Our capital spent drove production which exceeded the high end of our production guidance. As of January 30, 2015, we had $128 million drawn on our secured revolving credit facility, after paying down part of the balance with proceeds from our recent equity raise. Last year, our lenders approved a borrowing base increase of 114% to $750 million, but we elected to limit the commitment to $500 million, which we believe provides plenty of liquidity. We estimate our 2015 year end debt to EBITDA will be less than two times. At current commodity prices and with the current drilling programs, we expect that we will turn cash flow positive in the second half of this year. On Slide 20, we detail out our guidance for 2015. As previously announced we expect 2015 productions to range between 26,000 BOE and 28,000 BOE per day. This includes a range of 4,200 BOE to 2,500 BOE per day attributable to Viper. Turning to operating costs, our 2015 LOE is guided to the range of $6.50 to $7.50 per BOE. Our cash G&A projection is $1 to $2 per BOE and our non-cash equity compensation is also expected to be in the range of $1 to $2 per BOE. We have forecasted our DD&A rate between $20 to $22 per BOE and production and ad valorem taxes are guided at 7.1% of revenue. In 2015, we expect our capital spending to be in the range of $400 million to $450 million. I will now turn briefly to Viper Energy Partners, which recently announced a cash distribution of $0.25 per unit for the fourth quarter. During the quarter cash available for distribution was $20 million and production increased 24% quarter-over-quarter to 4,200 BOE per day. Viper has no debt and an undrawn revolver of $110 million as of December 31, 2014. Turning to Viper’s guidance, we expect 2015 volumes in the range of 4,200 BOE to 4,500 BOE per day. Production and ad valorem taxes approximately 7.5% of revenue. Our cash G&A projection is $1 to $2 per BOE, and our non-cash unit based compensation is expected to be in the range of $2 to $3 per BOE. DD&A is expected to be $20 to $22 per BOE. And as a reminder, Viper does not incur at least operating expenses or capital expenditures. I will now turn the call back over to Travis for his closing remarks.

Thank you, Tracy. To summarize our track record of capital discipline, stockholder returns and maintaining our strong balance sheet has prepared us for this downturn. The Lower Spraberry shale is delivering exceptional results. And we have increased our reserves substantially over last year at a very lower F&D costs. Our focus on costs, expenses and execution has never wavered and we continue to deliver cash margins per barrel and lower expenses at the top of our peer group. With our low cost structure and our ownership of minerals through Viper, we believe that we will generate significantly higher returns than most. We remain committed to growing the company through accretive transactions. I believe that it is in these challenging times that great companies are made and Diamondback Energy remains a low-cost producer in the highest return basin. Before I open the call for questions, I want to pause and acknowledge our employees for all they accomplished last year and have already accomplished this year. Even though we are in tough times with respect to commodity prices, I firmly believe our best is yet to come. Operator, please open the call for questions.

[Operator Instructions] Our first question comes from the line of David Amoss of Iberia Capital Partners. Sir, you may begin.

Good morning, guys.

Good morning, David.

Travis, I just wanted to see if I could get an update on what the pressure pumping backlog looks like in the basin right now, I know you talked about it a month ago, have you seen any improvement or where does that sit kind of on a relative basis versus where you are a month ago?

I think our friends on the pressure pumping side are probably the best to answer that. I can tell you from the operators’ perspective though there is a still quite a bit of backlog of completions that are really reflective of the really actively levels in the third quarter and fourth quarter of last year. That being said though while 2014 – at the end of 2014, we weren’t seeing much cost movement on the pressure pumping side. And really even honestly into the month of January, they were still a little bit slow to respond. I will tell you starting almost February 1 we have seen some – we started to see some cost concessions and we anticipate improvements in cost not only from pressure pumping guys, but really the rest of the service sector probably through the next couple of quarters.

Okay. And then as a reaction, when could or would you start to defer completions, if you are not getting the traction?

Yes, David, that’s a real good question. And quite honestly, as we were exiting ‘14 and not getting the cost concessions that I thought were reflective of $45 oil, we started deferring some completions. We had a dedicated frac crew, we let go and we are furloughing about a third of the days currently in a month right now deferring some completions. And we will continue to kind of build a small backlog of maybe a dozen or so or less wells until we can get the cost concessions that I believe are reflective of $50 oil. And at that time, we will potentially pick activity back up on the completion side. But that also is a pretty common phenomenon I am hearing around the basin as well, which I think probably why we started seeing some movement in costs effective February 1.

Alright. That’s really helpful. Thank you. Congratulations guys on a great quarter.

Thank you, David.

Thank you. And our next question comes from David Kistler of Simmons & Company. You may begin.

Good morning, guys.

Good morning, Dave.

Looking at the downspacing results in the Lower Spraberry that were impressive and certainly add to your inventory, can we assume that you would expect to see similar results in the Wolfcamp B, given similar rock qualities or maybe even slightly lesser rock quality than the Lower Spraberry?

Dave, that’s certainly something we are looking at pretty hard here internally. I can tell you right now, our current thinking – current thinking is probably that, that would be too tight for the Wolfcamp B, although I think the industry and Diamondback probably need to test some increased lateral, interlateral spacing or tighter spacing before we make that definitive statement, but right now our best thinking is probably that 10 across a section is probably not the right answer in the Wolfcamp B.

Okay, I appreciate that. And then maybe as a follow-up to that in the current commodity price environment, how do you guys think about doing delineation drilling, downspacing drilling or maybe even more specifically additional science work over the next, call it, 12 months or so maybe until either costs recalibrate appropriately or commodity prices look to improve?

Yes, certainly on the first point there, delineation drilling, we have outlined a three-rig program for this year and two of those rigs are being in Spanish Trail. So, that’s not – there is no delineation going there. That third rig, Dave, would be bouncing around between Northeast Andrews, Martin County, and a few drilling obligations we have. So, that – you kind of think of that third rig as a delineation rig. And then specifically to science, I have always been a little reluctant in a basin that’s got over 400,000 wells drilled to spend a lot of money on science instead preferring to spend our science dollars at the drill bit phase. That being said though, I think there is some – there is some really exciting technologies on the micro-seismic that can help us validate tighter spacing in our development scenarios and certainly now is the time to consider doing that versus running a multi – 8-rig program in our asset base that we would like to have answered this year. So, that’s probably the only science we are going to do is maybe a little bit of micro-science testing here in the next quarter and then we will see what happens after that.

Great. I appreciate that. And one last one just with Tracy’s comments about being free cash flow neutral in the second half of the year and looking at sort of the production guidance you guys have given us, in the event that you guys accelerated, how quickly do you think you could start bringing production growth back in a meaningful fashion on a quarter-over-quarter basis?

Yes, they are certainly – Dave, they are certainly measured in quarters. So, if we were to pick back up and start a full frac spread of completions starting in July, you probably wouldn’t see that, that effect until mid fourth quarter by the time you start getting everything online and producing. So, to the extent, we continue to defer completions, we will probably be at the lower end of our production guidance to the extent that we kind of pick up mid-year if there is a recalibration appropriately on service cost that probably pushes more towards the upper end of our range. But there is still a lot that has to play out on commodity price and service costs before we are going to increase activity.

Great, really appreciate the added color there Travis and also your commitment to capital discipline you kind of set a standard for others, appreciate that.

Thank you, Dave.

Thank you. And our next question comes from Michael Rowe of Tudor, Pickering Holt & Company. Your line is now open.

Hi good morning.

Good morning Michael.

Wanted to see maybe if you could provide or if you have enough information really at this point to quantify the impact of weather-related disruptions for Q1 that you all talked about in January?

Yes, we have probably got roughly for the quarter maybe 1,000 barrels a day or so of impact. It was really a 2 week event early on in January. And really by the 10th day we were pretty much on track to get everything back on and I think it should be noise in the first quarter, but we will wait and see how the quarter ends up.

Okay, that’s helpful. And just wanted to see if you could talk a little bit more about the cost reduction initiatives that you are working with on the LOE side, you kind of talked about on one of your slides I think it was – I can’t find the slide number off top of my head, but talk about some things you are trying to do to bring down LOE. And so I just wanted to see if you could maybe quantify what are the bigger drivers there of costs and I guess specifically you all can do from a competitive advantage standpoint versus your peers aside from just having the mineral barrels flowing through your financial statements?

Well, specifically Michael the well failure rate on these acquired properties was running around one, which means each one of these wells were failing once a year, that’s unacceptable for Diamondback standards. We need a well failure rate at 0.5 or below which means these wells should fail once every 2 years. And we had a lot of well maintenance related events due to poor pumping practices on these acquired properties that required us quite honestly to go in and look at everything from the pump placement, the metallurgy of the rods and the tubing that were in the ground as well as what we call telemetry which is a real-time monitoring of how that pumping unit performs most of these wells that didn’t have telemetry installed on so we could monitor performance. So we have gradually been upgrading these vertical wells at the same time instituting new field wide well failure reports, so that we can understand why these wells are failing and how to remediate it. And I guess rather than spend more time explaining that I mean, if you go back in our history, you can see that the reason I put that slide in there. This is the same dance that we were involved in trying to get the historical or the legacy vertical wells at Diamondback Energy pumping in the best in class fashion. So I have got a pretty good track record and I have got a very capable organization that’s well skilled in making these adjustments happen. So those are things we can absolutely control. And then the other one is that quite honestly we are seeing on the LOE side those people that support the expenses have been pretty quick to respond in reducing cost as well. So it’s a combination of really three things. It’s a combination of proactive pumping practices that we employee, it’s an inter-combination of increasing volumes and a combination of lowering service cost in these major LOE spend areas.

Okay. That’s great, and maybe just one last one if I could squeeze it in here would just be got some really phenomenal rates of return in the Lower Spraberry particularly when you factor in the mineral uplift and so just want to see if there is at any point where you would consider hedging maybe a little bit of volumes in 2016 to protect strong economics there and potentially maintain operational momentum heading into next year should commodity prices stay where they are or even kind of fall back a little bit? Thank you.

Yes, you bet Michael. And yes we have certainly considered hedging 2016 production. Curve’s is in contango right now and we just need to – we were studying it real closely. So, that’s a fair question and probably realistic expectations if we didn’t get the right prices in 2016, you will look to – we should look to mirror kind of what we have done in 2014, which is around 40% to 70% of our current production hedged.

Thanks, Travis.

Thank you. Our next question comes from Tim Rezvan of Sterne Agee. Your line is now open.

Hi, good morning folks. I had a quick question on Spraberry inventory. On Slide 16, you give that 348 net location, I know we spoke yesterday, you mentioned 225 in Midland County on 660-foot spacing. So, are you seeing you – I just want to clarify that roughly two-thirds of this inventory you list here is in that Midland County area?

Yes, that 225 number is not just Midland County, that’s Midland, Southwest Martin, Northwest Martin and kind of the southern half of our Northeast Andrews County acreage, where we have drilled that Tawny well and Mason well with real good results. So, that if you look at it for that area, if you assume 660-foot spacing, then we have got 220 Lower Spraberry locations remaining. If we can do it on 500-foot spacing or 10 laterals per section, then we are up at 277 locations remaining. And those counts are net wells at 7,500-foot equivalent lateral lengths.

Okay.

Yes. So, the 220 number is not just Midland County, it’s kind of at Midland, Martin, Andrews area that we think we have proved up with our results.

Okay. So, that delta, that 120 is really a kind of where you have less well control?

Yes.

Okay, I appreciate that update. And then lastly I know I am probably not going to get a good answer here, but you talked about being on the lookout for accretive acquisitions. I was wondering if you could give any kind of color on what the state of the M&A market is just from I am sure that you see all deal flow on your desk. And if you could define – explain what you defined as an accretive acquisition, whether that’s just kind of on NAV basis or what the metrics you are looking for? Thanks.

You debt. Thanks, Tim. Yes, certainly, there is – we are seeing a lot of the M&A activity out here in the Permian Basin. I don’t know if the full effect of low commodity prices and distressed assets has been felt yet, probably more of a mid-year or late 2Q event. But one thing, I do note, Tim, is that – is the position that Diamondback has placed themselves in, not only with our execution prowess, but also our pristine balance sheet in the M&A activity that, that is ongoing in the Permian. I think my shareholders should expect Diamondback to be right in the middle of that, if not the first call that’s being made. So, I know you said you probably weren’t going to get a good answer and that’s probably not a good answer, but that’s kind of how we think about it. Accretive EBITDA per share is usually a good one that we kind of look at, but then there is multiple accretion metrics as well, reserves production, acreage etcetera as well.

Okay, thank you.

Thank you. Our next question comes from Adam Michael of Miller Tabak. Your line is now open.

Good morning, guys. My question is centered around the PUD reserves that were booked. And I noticed in the presentation that you have 64 locations booked as PUDs and I think your guidance was for 50 to 60 wells this year and that’s with reduced rig count. It just seems a little conservative and I wanted to maybe just see if we could get a little more color on kind of the thought behind the PUD bookings and it certainly seems like you could have booked twice as many PUDs with the drilling inventory that you had in the 5-year rule, even with the reduced rig count. So, maybe just a little more color there please?

Yes, that 64 locations, that’s a net number. It’s 79 gross horizontal wells that we have booked as PUDs and 53 of those are in the Wolfcamp B, 20 are in the Lower Spraberry. So, we had a lot of several of our Lower Spraberry wells that we talk about came on either real late in 2014 or actually early 2015. And so we didn’t have any PUDs booked to offset to those wells. And we have generally been conservative along Ryder Scott on our PUD booking. We generally only book PUDs one location away. So if you look at it right now we have got 15 Lower Spraberry wells on production and nearly 20 Lower Spraberry PUDs. So I mean it is a fairly conservative number, but we have generally been conservative in the way we have looked our PUDs over time. So it’s as you mentioned it’s quite not early a reflection of our inventory. And we have obviously got a lot of good inventory in the Lower Spraberry and also remaining in the Wolfcamp B as well.

It’s refreshing to see especially in light of some of your peers and how they have approached PUDs, but that’s it from me. Thanks guys.

You bet. Thanks Adam.

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

Just curious, Travis as you look and then obviously the three rigs you are going to be running hereafter February, as things improve, or obviously given the returns you are making, if you would look to add another rig at some point, is there a thought to continuing Spanish Springs, is there a thought to go to other areas or maybe even the other formation which is continue on with Lower Spraberry which maybe either move back to the move to the B or perhaps even to something else, just kind of curious the thoughts there?

Yes. Certainly Jason for us to increase activity is going to require continued service cost and some stability in the oil price probably in the $65 to $75 range. And if we were to pick another rig up, we would likely move that into our recently acquired acreage over in Glasscock County and Midland County where we know we have got some really, really nice results both in the Spraberry and Wolfcamp B. So that’s probably where that rig would go and we would just leave the two rigs in Spanish Trials working and one rig there are in some delineation work accordingly.

That’s helpful. And then you kind of mentioned about the LOE and the things you can do as far as driving the cost down at obviously guide that you put out for 2015, just as far cadence looking at that throughout the year is that going to be pretty gradual reduction as you kind of work through that for lack of better word backlog of wells that you have been worked on, that you acquired or just how you see that playing out?

Yes, exactly I wish like it’s not my fingers and make it happen over night but there is just a lot of hard work that has to go in to fixing these legacy issues, so I expect sort of a quarter-over-quarter decline that’s going to get us in that $6.50 to $7.50 range, by the end of the year.

Great, I will turn it back. Thank you.

Thank you, Jason.

Thank you our next question comes from Mike Kelly of Global Hunter Securities. Your line is now open.

Hey guys, good morning.

Good morning Mike.

Travis, your F&D costs and they certainly speak to thanks for your capital efficiency relative to the industry and your other permanent peers. And my question is I am just curious of how or where you see the probably the biggest opportunities going forward to continue to push your operational efficiencies that really if you continue this downward trend of the de-cost effects?

Yes, and certainly I will look on two of the major spend areas on drilling these wells, which is the drilling side and then the completion side. Right now it’s about – of the total it’s about 40% allocated to the drilling side and about 60% on the completion side. On the completion side of that 60%, about half of that is related to pressure pumping. And so as we continue to see reductions in pressure pumping cost that’s going to translate to lower cost as well too. And then on the drilling side, we continued to optimize our efficiency both in terms of how fast we get to PD and then also with the other ancillary costs that are associated with drilling these wells. And so it’s really not a single actually one or two item that I could point to that’s going to push our cost lower. It’s really all those steps the completion guys do on their side of the equation delivering completed well cost, invest in class fashion as well as the drilling guys drilling these wells faster and faster so it’s kind of an efficiency thing. So, it’s really the combination of a 1,000 decisions we make on a daily basis not just one or two decisions on a quarter basis.

Understood. And then if we look at recoveries and 2015’s program is going to be core to drill and arguably your best of Spanish Trail’s. What’s kind of a ballpark way we should think about the average well EUR uptick in ‘15 versus ‘14’s program?

I would say, probably you are looking at maybe 10% or 15% uptick. I think we have said probably two-thirds of our wells will target the Lower Spraberry roughly 25% in the Wolfcamp B and then we will probably have a couple of tests in some other zones, including the Middle Spraberry and the Wolfcamp A as we do some stack tests. So, a little bit more weighted more to the Spraberry this year than last year and as long as we continue to see the results we have seen so far in the Lower Spraberry, I think that 10% to 15% uptick is probably a pretty reasonable number.

Great. I appreciate it. Thank you.

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

Good morning, everyone. Travis, just a quick question, looking at the vertical PUDs booked, I saw you took down by 6.2 million barrels at year end ‘14. Just wondering if the ones you still have on the books, are those of younger vintage? Is that why they are still there or there is any other reason?

Yes, I mean, they are younger vintage and they are also in the areas where we have seen better EURs from our vertical wells. So, some of the ones that part of that 73 were ones that we weren’t going to get drilled within the 5 years, but we also took some off that were kind of in our lower EUR areas that would probably have to come off at the end of – into 2015 assuming that commodity prices stay low.

And I guess – I am sorry, go ahead.

No, go ahead.

Just to follow on that, with the location count on the vertical side, I guess at what point do you guys start taking down some of those, if we are in a 1-year or 2-year kind of prolonged, maybe even longer commodity price weakness?

Yes. I mean, we will just have to see how the commodity price plays out. Some of those locations are in – or probably about half of those locations are in Spanish Trail, where we own the minerals. So, it has considerably better economics than a typical vertical well. So, obviously, our horizontal wells are delivering better returns and that’s where the focus will remain, but we will just see how that plays out by the end of the year.

Alright, thanks for the answers guys.

Thanks, Jeb.

Thank you. Our next question comes from Richard Tullis of Capital One Securities. Your line is now open.

Hey, good morning everyone. Couple of quick questions related to M&A continuing with that theme, Travis. As you look at the landscape right now given everything the commodity prices, your efficiencies, are you willing to look outside the Midland Basin if you see appropriate attractive opportunity, say it were in the Delaware basin or even outside the Permian at this point, Travis?

Yes, Richard, what I would tell my guys, there is really no bad deals, there is just bad pricing. And so from the Viper perspective, we have been looking outside the Permian for Viper and not so much Diamondback, but the logical progression for Diamondback would probably be in the Delaware Basin, but it’s pretty exciting in one regards and it’s also pretty confusing in terms of what really is going to transpire in this M&A environment, because of all the new private equity money that’s been raised, that’s looking for a home in the Permian Basin. Some folks are thinking this maybe the best chance to get into the Permian. So, again like I was talking to Tim earlier, I don’t know exactly how it’s all going to play out, but I do know with the fortress balance sheet and our execution record that we ought to be in all those conversations.

Okay. And then just going back to Viper, Travis, how are things progressing, looking to add mineral interests there, is the bid/ask spread still fairly wide or are you seeing attractive opportunities?

Yes, I would say that the bid/ask rate is still pretty wide for cash types of transactions, because the commodity price is down 55% or 60% since we IPO’d the Viper Energy Partners, but one thing that we are always trying to get a little bit of traction with is the acknowledgment that receiving Viper units from minerals is starting to have some appeal at these prices. So, we are engaged and we are looking hard and we will report when we close something.

Alright. Well, that’s it for me. Thanks very much.

Thanks, Richard.

Thank you. Our next question comes from Michael Hall of Heikkinen Energy Advisors. Your line is now open.

Thanks. Congrats on the good update. A lot of mine have, I guess, been addressed, but just kind of follow-up on some of the existing questions, just to make sure I am understanding it right, as it relates to the weighting on completion backlog, you said you kind of build up around a dozen wells waiting on completion. Does the current guidance assume those are drawn down or is it maybe fair to say that the low end assumes that those remain in backlog as you make your way through the full course of the year and the higher end of guidance then – seems those get put on in the second half?

Yes, Michael. I think I was – I think I tried – maybe I didn’t do it efficiently, but I will try to address that earlier. To the extent, we maintain a backlog of completions through the middle of the year we will probably be more towards the lower end of our production guidance range. To the extent that we reinitiate the pressure pumping side of the equation and get another crew in, we will probably push it more towards the higher end. And the other thing is, is that we continue to be surprised as we outlined a numerous points in our prepared remarks this morning by this Lower Spraberry. And what we tried to account for that in our production guidance, these wells are certainly surprising us to the upside and that doesn’t usually happen in our business. So, to the extent, we bring more and more Lower Spraberry wells on and surprise us positively, that will also help push us towards the upper end of our production guidance.

Great. And I guess as we think about that Lower Spraberry, one other question I had was just around on the downspacing side, is the Spraberry consistent enough throughout all the various portions of the portfolio that that downspacing assumption is fair to take across the board, do you think or would you….

I think it’s a little early right now, Michael, to say all the way across our portfolio, because if you look, I think I got a slide in the slide deck that shows we have now got economic test from Dawson County all the way down to Upton County. That’s about 120 miles. And so I think it would be a little bold at this point to step out and say everywhere you can downspace, but I will tell you if you just look at unconventional resource plays around the United States, typically over time they get spaced tighter and tighter. Whatever they start off with is usually not where they end up with. And of course, you got to balance that with the risk of overcapitalization. So, that’s why I think it’s prudent for Diamondback to continue to test this downspacing in a way that allows us as much optionality in the future to continue developing in a full-scale fashion at the right spacing intervals.

That’s helpful. And what was it about the Wolfcamp B that you said that maybe you all weren’t quite as optimistic about the opportunity to downspace there to 500-foot interlateral spacing? What is it about that reservoir that is kind of pointing you in that direction, I am just curious?

Yes, I mean, of course this varies across different peoples, I agree, but when you look at our acreage, we think there is a reasonable frac barrier between the Wolfcamp A and B. And so you are probably generating more fracture half-length and less height than the B. If you look at the Lower Spraberry, which overall is quite a bit thicker than the B, but you really don’t have any barriers to height growth.

Okay.

So, you are generating as much height as half-length and that’s the reason. Really two reasons we think we can go to tighter spacing on the Spraberry and that is we are probably not generating is much effective length and you have got a lot more oil in place in this Spraberry, as well.

That’s helpful color. Thanks. And then last of mine, I guess on the somewhat recently acquired acreage in Glasscock and Western Midland, is there any leasehold expiration considerations that need to be taken into account even if I keep in mind, that if prices remain low for long, that might force some activity over there?

Yes. Michael we have got a good handle on that. And the guidance we have given for this year incorporates maintaining leases not only in the Glasscock County, but across our acreage position.

Fair enough. Thanks. I appreciate that.

Thank you. Our next question comes from Gail Nicholson of KLR Group. Your line is now open.

Good morning everyone. I am looking at the Dawson County that Lower Spraberry test was a really solid well, has there been any difference in that well behavior versus your Midland area Lower Spraberry wells?

Yes. I mean it’s a nice result, it’s obviously not as good as what we have seen in Midland County or even Northwest Martin, Northeast Andrews you can see that from the 30 day rates, but still a nice well. It has decent economics at $50 oil, it’s probably in that 15%, 20% rate of returns of really we probably need higher oil prices in the $65 to $70 a barrel before we go there and drill much offset wells there. But still nice results overall.

And then in that Lower Spraberry location count that you guys provided in the horizontal count how many are allocated to Dawson?

I think right now we have got I think there are 24 wells that we have in Dawson and obviously if it works I mean there is more potential locations in that but we risk that number down for Dawson until we get some more results.

Okay, great. And then looking on Page 13 in the presentation and looking at the Lower Spraberry on well results that you have there, have there been any different method of completion techniques within those Midland County Lower Spraberrys or you have been completing them the same way I mean those lateral lengths have varied, but I wasn’t sure if you are putting more propane or doing spacing with the frac stages anything different on those?

It’s been pretty much the same recipe we have done some testing with 30-50 a little bit larger sand in this Spraberry, but in the general sense we have maintained that 240 kind of foot inter-stage spacing and 300,000 or so pounds of total sands per stage that’s kind of being our go to. And you have heard us talk a little bit about shortening that inter-stage distance maybe down to 150-feet or so. And we are continuing to experiment with that and still way too early on to talk about whether or not we have got positive results. But we continue to try to tweak on these stimulation designs, because never satisfied that we have got the right answer, in fact our history says that these things evolve over time, so we want to make sure we are pushing that evolution.

Okay. Thank you.

Great Gail. Thanks.

Thank you. And our next question comes from Abhi Sinha of Wunderlich Securities. Your line is now open.

Yes. Hi, good morning everybody. Just want a quick update on Viper’s inventory, so has your estimate of like 127 wells that’s what I thought for Lower Spraberry changed and what about the total number of horizontal drilling locations that was like 1,060 last time when we got an update?

Yes. I am not sure I have caught all of that, are you talking about the number of locations in Viper’s inventory?

Yes, sir. So it was 127 wells in the Lower Spraberry for Viper’s inventory?

Yes. That’s still based on the 660-foot spacing. We haven’t increased that number yet for further down spacing.

Sure. And I believe the total horizontal drilling locations also remain the same like 1060 where it was before?

That’s correct.

Sure. And any word that you can throw on basically what your plan could be in 2016 that last time it was like you are expecting four horizontal rigs in Viper’s take rates, everything including RSP Permian, I guess. So, do you think that would still be – might be the case?

Yes. Obviously, we have not provided a lot of – any color on 2016. But that’s probably a reasonable assumption.

Sure. And then lastly, I just wanted to see has your hedging strategy changed a bit given the downturn that we have seen, I mean, when commodity picks up, I mean, do you think you might be willing to add hedges to Viper’s volumes as well?

No, we won’t hedge, Viper. We have been pretty clear that we believe the most efficient form of transfer to our unitholders is to remain un-hedged. And we are constructive at the Viper level on the price of oil long-term and we are going to stay un-hedged at the Viper level. And there is really nothing to provide hedge insurance against. I don’t have any maintenance capital. I don’t have any IDRs or anything that would need to preserve. I just want to pass in the most efficient possible manner that I can revenue from mineral production back to my unitholders.

Sure. That’s all I have. Thank you very much, sir.

Thank you. [Operator Instructions] Our next question comes from Ryan Oatman of SunTrust. Your line is now open.

Hi, good morning.

Good morning, Ryan.

At the risk of beating a dead horse, I would like to touch a little bit on the spacing a little bit more. I see Slide 15 kind of going through the stacked pay potential in Spanish Trail. I was wondering if you could provide any insight as to whether the spacing varies by area, whether the mineral ownership helps you there, whether say in Upton County, you would see the spacing similarly or different and if so how?

Yes, I mean, you are right. I mean, the mineral ownership obviously helps on the spacing, but really when we look at the spacing, we would kind of look at all aspects, how much oil in place and thickness per zone and what kind of half length we think we are good. So, specifically to Upton County, generally in most of the zones, where we are at in Upton, the pay is a little thinner in both the Wolfcamp B and in the Lower Spraberry. And we have drilled a lot of Wolfcamp B wells down in Upton County. We actually did that on 880-foot spacing and just because that the B was thinner there and we thought we had a fairly good frac area. And as we look back on it, we really haven’t seen any interference down in Upton County and the B. And so maybe we should have developed that a little tighter than we did. So, as we have got one Lower Spraberry well in Upton, we have just completed two more. We will have some results on in a few months. We drilled those at 660-foot spacing. So, we will test a little tighter spacing down in Upton in the Lower Spraberry than that we did in the B. And we will just see how the results work out. As we look at the Lower Spraberry across the rest of our acreage, it’s fairly similar thickness up in the north area, up in Andrews and Martin and in Glasscock County as well. So, we will test tighter spacing there early on in those areas to guide us on what our ultimate development will be, but we think in those areas, it ought to be pretty similar to what we can – what we are doing in Midland County.

That’s very helpful. And then just a clean up one for me, can you refresh me on your oil pricing exposure roughly how much is Brent versus LS versus Cushing versus Midland?

You are talking about our hedge, Ryan or hedge volumes or how much production we have?

No, I understand on the hedges.

Okay.

And I can kind of see that you guys hedge at different pricing points. I guess, I am just kind of trying to think about the physical marking kind of your ex-hedged volumes, where all that’s going and what sort of pricing you are getting there conceptually?

Yes, we got – I am sorry, we got 8,000 barrels a day that go to Magellan Longhorn down to Houston Ship Channel. And that receives at LLS pricing, all the remaining barrels we produced at this point go to Cushing, Oklahoma.

That’s it for me. Thank you.

Thank you. At this time, I am showing there are no further participants in the queue. I would like to turn the call over to Travis Stice CEO for any closing remarks.

Thanks, again to everyone 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 your participation on today’s conference. This concludes the program. You may now disconnect. Everyone have a great day.