Ladies and gentlemen, and welcome to the Diamondback Energy and Viper Energy Partners 4th Quarter 2014 Earnings Conference Call. At this time, all participants are 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 4th quarter year end 2014 conference call. During our call today, we'll reference 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
in the company's filings with the SEC. I'll 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' Q4 2014 conference call. Last month in our update, we announced 4th 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 6 60 foot spacing. We believe our 2nd Lower Spraberry test in Andrews County and our 1st test in Dawson County confirm 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 7,500 foot lateral in Midland County to 990,000 BOE equivalent on a 2 stream basis from 6.50 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 113,000,000 barrels of oil equivalent at an associated drill bit finding and development cost of $11.09 per barrel. Proved developed reserves increased 122 percent over last year to 66,500,000 barrels. Additionally, last month we strengthened our already strong balance sheet by issuing Pro form a for the proceeds from the equity raise, our net debt to annualized 4Q 2014 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 1,000,000 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 and D costs have decreased to $11.09 per barrel during 2014 from $14.46 per barrel in 2013. This is a reduction in F and D of almost 25%, reflecting the early promising results of 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 2014 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 14 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 first to have the full impact from the properties that closed in September. We're working hard to apply our low cost efficient practices on these properties and expect to average between $6.50 $7.50 per barrel in 2015. Slide 10 shows how our vertical wells and LOE per barrel have changed since the Q4 of 2012. In 2013, we decreased LOE from $11.39 to $6.04 in the 4th quarter as we increased the amount of horizontal wells drilled and drove costs lower. We're 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're in the process of dropping 2 horizontal rigs this month and have already released our remaining vertical rig. In 2015, we expect to run 3 horizontal rigs, including 2 in Spanish Trail where Viper owns the underlying minerals. Slide 12 shows how the Permian rig count and WTI prices have changed since 2,001. 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 16.50 net potential horizontal locations shown in Slide 16, less than 4% are currently booked as PUDs. Assuming the midpoint of EUR ranges, we have over 800,000,000 barrels of resource potential remaining based on net locations in our inventory. With these comments now complete, I'll turn the call over to Tracy.
Thank you, Travis. Diamondback's net income for the quarter was $98,700,000 or $1.74 per diluted share after adjusting our 4th quarter earnings for non cash mark to market derivative gain of $111,500,000 and netting out the related income tax effect, our adjusted net income was $27,300,000 or $0.48 per diluted share. Diamondback's adjusted EBITDA for the quarter was $111,700,000 Our average realized price for the Q4 was $55.60 per BOE and due to the positive impact of 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 barrels 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, 4th quarter was the Q1 with the full effect of bulk acquisition. 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 Q4.
This includes non cash equity based compensation. Excluding equity comp, G and A is $1.02 per BOE. In the Q4 of 2014, Diamondback generated $104,400,000 of operating cash flow and $106,800,000 of discretionary cash flow or $1.83 and $1.87 per diluted share respectively. During 2014, we spent approximately $487,000,000 for drilling, completion and infrastructure. Our capital spend drove production, which exceeded the high end of our production guidance.
As of January 30, 2015, we had $128,000,000 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 percent to 750,000,000 dollars but we elected to limit the commitment to $500,000,000 which we believe provides plenty of liquidity. We estimate our 2015 year end debt to EBITDA will be less than 2 times. At current commodity prices and with the current drilling program, 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 production to range between 26,000 and 28,000 BOE per day. This includes a range of $4,200 to $4,500 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 and 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 and A 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 spend to be in the range of $400,000,000 to 450,000,000 dollars I'll now turn briefly to Viper Energy Partners, which recently announced a cash distribution of $0.25 per unit for the 4th quarter. During the quarter, cash available for distribution was $20,000,000 and production increased 24% quarter over quarter to 4,200 BOE per day. Viper has no debt and an undrawn revolver of $110,000,000 as of December 31, 2014. Turning to Viper's guidance, we expect 20.15 volumes in the range of 4,200 Boe to 4,500 Boe per day. Production and ad valorem tax is approximately 7.5 percent of revenue.
Our cash G and 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 and A is expected to be $20 to $22 per BOE. And as a reminder, Viper does not incur lease operating expenses or capital expenditures. I'll now turn the call back over to Travis for his closing remarks.
Thank you, Tracy. To summarize, our track record 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've increased our reserves substantially over last year at a very low F and D cost. Our focus on costs, expenses and execution has never wavered and we continue to deliver cash margins per barrel and low 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 to questions.
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, 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 about a month ago. Have you seen any improvement? Or where does that sit kind of on a relative basis versus where you were a month ago?
Yes. I think our friends on the pressure pumping side are probably the best to answer that. I can tell you from the operator's perspective though, there's still quite a bit of backlog of completions that are really reflective of the really high activity levels in the Q3 Q4 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 end of the month of January, they were still a little bit slow to respond.
I'll tell you starting almost February 1, we've seen some we're starting to see some cost concessions and we anticipate improvements in cost not only from the 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're not getting the traction?
Yes, David, that's a real good question. And quite honestly, as we were exiting 2014 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're furloughing about a third of the days currently in a month right now deferring some completions. And we'll 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'll potentially pick activity back up on the completion side. But that also is a pretty common phenomenon I'm hearing around the basin as well, which I think is probably why we started seeing some movement in costs effective February 1.
All right. That's really helpful. Thank you. Congratulations guys on a great quarter.
Thank you, David.
Thank you. And our next question comes from David Kessler 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 spreader? Dave, that's certainly something we're looking at pretty hard here internally. I can tell you right now our current thinking is probably that that would be too tight for the Wolfcamp B. Although, I think industry and Diamondback probably need to test some increased lateral interlateral spacing or tighter spacing before we make that a definitive statement. But right now our best thinking is probably that 10 across the section is probably not the right answer and
the Wolfcamp B. Okay. 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, down spacing 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've outlined a 3 rig program for this year and 2 of those rigs will be in Spanish Trail. So that's not there's no delineation going there. That 3rd rig Dave would be bouncing around between Northeast Andrews, Martin County and a few drilling obligations we have. So that you can kind of think of that 3rd rig as a delineation rig.
And then specifically the science, I've always been a little reluctant to 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's some really exciting technologies on the microseismic 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'd like to have answered this year. So that's probably the only science we're going to do is maybe a little bit of micro science testing here in the next quarter and then we'll 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. There's certainly Dave. There's 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 effect until mid Q4 by the time you start getting everything online and producing. So to the extent we continue deferred completions, we'll probably be at the lower end of our production guidance.
To the extent that we kind of pick up mid year with if there's a recalibration appropriately of on service cost that probably pushes more towards the upper end of our range. But there's still
a lot that has to play out on commodity price and service cost before we're going to increase activity. Great. Really appreciate the added color there Travis and also your commitment to capital discipline. You kind of set standard for others. Appreciate that.
Thank you, Dave.
Thank you. And our next question comes from Michael Rowe of Tudor, Pickering, Holt and Company. Your line is now open.
Hi, good morning.
Good morning, Michael.
I wanted to see if maybe just if you could provide or if you have enough information really at this point to quantify the impact of weather related disruptions Q1 that you all talked about in January?
Yes. We've 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 Q1, but we'll 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're 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 the top of my head, but you talked about some things you're 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 what 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 1, 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 every 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 didn't have telemetry installed on so that we could monitor performance.
So we've gradually been upgrading these vertical wells at the same time instituting field wide well failure reports, so that we can understand why these wells are failing and then 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 we 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've got a pretty good track record and I've got a very capable organization that's well skilled in making these adjustments happen. So those are the things we can absolutely control. And then the other one is that quite honestly we're seeing on the LOE side those people that support the expense 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 employ. It's a 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 you've got some really phenomenal rates of return in the Lower Spraberry, particularly when you factor in the mineral uplift. And so just wanted to see if there was 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.
Yeah. You bet, Michael. And yes, we've certainly considered hedging 2016 production curves and contango right now. We just need to you're studying it real closely. So that's a fair question and probably realistic expectations.
If we can get the right prices in 2016, you'll look to we should look to mirror kind of what we've 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 Carnegie. 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 6 60 foot spacing. So are you saying you I just want to clarify roughly 2 thirds of this inventory you list here is in that Midland County area?
Yes. That $225,000,000 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've drilled that Taney well and Mason well with real good results. So that if you look at it for that area, if you assume 6 60 foot spacing, then we've got 220 Lower Spraberry locations remaining. If we can do it on 500 foot spacing or 10 laterals per section then we're 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 that Midland Martin Andrews area that we think we've proved up with our results.
Okay. So that delta that 120 is really a kind of where you have less well control?
Yes.
Okay. Okay. Appreciate that update. And then lastly, I know I'm 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 and A market is just from I'm sure that you see all deal flow on your desk.
And if you could define explain what you define as the accretive acquisition whether that's just kind of on an NAV basis or what the metrics you're looking for? Thanks.
You bet. Thanks, Tim. Yes, certainly, there's we're seeing a lot of M and A activity out here in the Permian Basin. I don't know if the full effect of low commodity prices and distressed assets hasn't felt yet, probably more of a midyear or late 2Q event. But one thing I do know Tim is that the position that Diamondback has placed themselves in not only with our execution prowess, but also our pristine balance sheet.
Any M and A activity 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 shares is a good one that we kind of look at. But then there's 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.
Hi. 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 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 a 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 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 20 14 or actually early 2015. And so we didn't have any thoughts booked offset to those wells.
And we've generally been conservative along with Rod or Scott on our car PUD booking. We generally only book PUDs one location away. So if you look at it right now, we've got 15 Lower Spraberry wells on production and only 20 Lower Spraberry. So I mean it is a fairly conservative number, but we've generally been conservative in the way we looked our PUDs over time. So it's as you mentioned, it's probably not really a reflection of our inventory.
We've 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've approached PUDs. But that's it for me. Thanks, guys.
You bet. Thanks Adam.
Thank you. Our next question comes from Jason Wangler of Wendellix Securities. Your line is now open.
Just curious, Travis, as you look and obviously the 3 rigs are going to be running here after February, if things improve or obviously given the returns you're making,
if you were to look
to add another rig at some point, is there a thought to continue in Spanish Springs? Is there a thought to go to other areas or maybe even the other formations, which is continue on with the lower spray barrier, which you maybe either move back to the B or perhaps even to something else? Just kind of curious the thoughts there.
Yes. Certainly, Jason, for us to increase activities 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 the Glasscock County and Midland County where we know we've got some really, really nice results both in the Spraberry and the Wolfcamp B. So that's probably where that rig would go and just leave the 2 rigs in Spanish Trails working in 1 rig doing 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 cost down and obviously the guidance you put out for 2015. Just as far as the cadence looking at that throughout the year, is that going to be a pretty gradual reduction as you kind of work through that for lack of better word backlog of wells that need to be worked on that you acquired? Or just how you see that playing out?
Yes, exactly. I wish I could snap my fingers and make it happen overnight, but there's 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 $650,000,000 to $750,000,000 range by the end of the year.
Great. I'll turn it back. Thank you.
You bet. 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.
Hey Travis, your F and D costs certainly speak to thanks for your capital efficiency relative to the industry and your other Permian peers. And my question is, probably the biggest opportunities going forward to continue to push your operational efficiencies that really could continue this downward trend in F and D cost? Thanks.
Yes. Certainly, I look on 2 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 dollars, 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 costs, that's going to translate to lower cost as well too.
And then on the drilling side, we continue to optimize our efficiency both in terms of how fast we get to TD and then also with the other ancillary costs that are associated with drilling these wells. And so it's really not a single actually 1 or 2 item that I could point to that's going to push our costs lower. It's really all the stuff that completion guys do on their side of the equation, delivering completed well cost in a best 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 a combination of 1,000 decisions we make on a daily basis, not just 1 or 2 decisions on a quarter basis.
Understood. And then if we look at recoveries and 20 fifteen's program is going to be cored up drilling arguably best of Spanish trails. What's kind of a ballpark way we should think about the average well EUR uptick in 2015 versus 14 program?
I'd say probably you're looking at maybe 10% or 15% uptick. I think we've said probably 2 thirds of our wells will target the lower Spraberry, roughly 25% in the Wolfcamp B and then we'll 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 mortgage spray berry this year than last year. And as long as we continue to see the results we've seen so far in the lower spray berry, I think that 10% to 15 percent uptick is probably a pretty reasonable number.
Great. Appreciate it. Thank you.
Thank you. Our next question comes from Jed Batman of Howard Weil. Your line is now open.
Good morning, everyone. Travis, a quick question. Looking at the vertical PUDs book, you saw you took down about 6,200,000 barrels at year end 2014. Just wondering if the ones you still have on the books, those of younger vintage that why they're still there or there's any other reason?
Yes. I mean they are younger vintage and they're also in the areas where we've 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 2015 assuming that commodity prices stay low.
And I guess I'm 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're in a 1 or 2 year kind of prolonged maybe even longer commodity price weakness?
Yes. I mean we'll 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, I have 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'll just see how it plays out by the end of the year.
All right. Thanks for the answers guys.
Thanks, Jim.
Thank you. Our next question comes from Richard Tullis of Capital One Securities. Your line is now open.
Hey, good morning, everyone. A couple of quick questions related to M and 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 over in the Delaware Basin or even outside
the Permian at
this point Travis? Yes. Richard what I tell my guys there's really no bad deals. There's just bad pricing. And so from the Viper perspective, we've 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.
Pretty exciting
in one regard and it's also
pretty confusing. Pretty exciting in one regard and it's also pretty confusing in terms of what really is going to transpire in this M and 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 may be 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 of those conversations.
Okay. And then just going back to Viper, Travis, how are things progressing looking to add mineral interest there? Is the bid ask spread still fairly wide or are you seeing attractive opportunities?
Yes. I would say that the bid ask spread is still pretty wide for cash types of transactions because the commodity price is down 55% or 60% since we IPO ed the Viper Energy Partners. But one thing that we are starting to get a little bit of traction with is the acknowledgment that receiving Viper units for minerals is starting to have some appeal at these prices. So we're engaged and we're looking hard and we'll report when we close
All right. 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 a good update. A lot of items I guess been addressed, but just kind of follow-up on some of the existing questions. Just to make sure I'm understanding it right, as it relates to the waiting on completion backlog, you said you kind of build up around a dozen maybe fair to say that the low end assumes that those 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 since those get put on in the
second half? Yes, Michael, I think I was thinking I tried to maybe I didn't do it efficiently, but I tried to address that earlier. To the extent we maintain a backlog of completions through the middle of the year, we'll probably be more towards the lower end of our production guidance range. To the extent that we reinitiate the pressure pumping side equation and get another crew in, we'll probably push it more towards the higher end. And the other thing is that we continue to be surprised as we outlined at numerous points in our prepared remarks this morning about this Lower Spraberry.
And while we tried to account for that in our production guidance, these wells are certainly surprising us to the upside and that's doesn't usually happen in our business. So to the extent we bring more and more Lower Spraberry wells on, it surprises 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 you think? Or
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've now got economic test from Dawson County all the way down to Upton County, that's about 120 miles. And so I think it'd be a little bold at this point to step out and say everywhere you can down space. But I'll 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 over capitalization.
So that's why I think it's prudent for Diamondback to continue to test this down spacing 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.
Okay. 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 down space there to 500 foot lateral spacing? What is it about that reservoir that kind of pointing you in that direction? I'm just curious.
Yes. I mean, of course, this varies across different people's acreage. But when you look at our acreage, we think there's a reasonable frac barrier between the Wolfcamp A and B. And so you're 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.
So you're 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're probably not generating as much effective length and you've got a lot more oil in place in the Spraberry as well.
Helpful color. Thanks. And then last on 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? I want to keep in mind if prices remain low for long that might force some activity over there?
Yes. Michael, we've got a good handle on all that. And the guidance we've given for this year incorporates maintaining leases not only in the Glasgow County but across our acreage position.
Fair enough. Thanks. Appreciate it. Appreciate that.
Thank you. Our next question comes from Gail Nicholson of KLR Group. Your line is now open.
Good morning, everyone. I'm looking at that Dawson County, the 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've seen in Midland County or even Northwest Martin, East Andrews, you kind of see that from the 30 day rates, but still a nice well, has decent economics at $50 oil, it's probably in that 15% 20% rate of return. So really we probably need higher oil prices in the $65 $70 a barrel before we go up there and drill much offset wells to it, but still a nice result overall. And then in that result 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've got I think there's 24 wells that we have in Dawson. Obviously, that works. I mean there's 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 of the presentation and looking at the Lower Spraberry well results that you have there, have there been any different method of completion techniques within those Midland County Lower Spraberry? Or have you been completing them the same way? I mean, I know lateral lanes have buried, but I wasn't sure if you're putting more proppant or doing spacing with the frac stages anything different on those?
No, it's been pretty much the same recipe. We've done some testing with 3050, a little bit larger sand in the Spraberry. But in a general sense, we've maintained that 240 kind of foot inner stage spacing and 300,000 or so pounds of total sands per stage That's kind of been our go to. And you've heard us talk a little bit about shortening that interstage distance maybe down to 150 feet or so. And we're continuing to experiment with that and still way too early on to talk about whether or not we've got positive results.
But we continue to try to tweak on these stimulation designs because never satisfied that we've got the right answer. In fact, our history says that these things evolve over time. So we want to make sure we're pushing that evolution.
Great. Thank you.
You bet, Gail. Thanks.
Thank you. And our next question comes from Abhi Sanath of Wonder Luck 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 127 wells, that's what I thought, for Lower Spraberry changed?
And what about the total number of horizontal drilling locations? I think that was like 10 60 last time when we got an update.
Yes. I'm not sure I 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. I mean that's still based on the 6 60 foot spacing. We haven't increased that number yet for further down spacing. Sure.
And I believe the total horizontal ring locations also remain the same like around 1060 where it was
before? That's correct.
Sure. And any word that you guys throw on basically what's your plan could be in 2016? I thought last time it was like you were expecting 4 horizontal rigs and Wiper safe rigs everything including RSP Permian I guess. So do you think that would still be might be the case?
Yes. Obviously we've not provided a lot of any color on 2016, but that's probably a reasonable assumption.
Sure. And then lastly, I just want to see has your hedging strategy changed a bit given the downturn that we have seen? I mean, when commodity picks up, I mean, 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've been pretty clear that we believe the most efficient form of transfer to our unitholders to remain unhedged. And we're constructive at the Viper level on the price of oil long term and we're going to stay unhedged at the viper level. And there's really nothing to provide hedge insurance against. I don't have any maintenance capital.
I don't have any IDRs or anything that I 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.
Got it. Sure. That's all
I have. Thank you very much, sir.
Thank you. Our next question comes from Ryan O'Thman of SunTrust. Your line is now open.
Hi, good morning.
Good morning, Ryan.
At the risk of
a beating dead horse, I would like to touch a little bit on the spacing a little more. I see slide 15 kind of going through the stack pay potential in Spanish Trail. I was wondering if you provide any insight as to whether the spacing varies by area or whether the mineral ownership helps you there, whether say in Upton County you see the spacing similarly or different and if so how?
Yes. I mean, you're right. I mean the mineral ownership obviously helps on the spacing. But if you really when we look at the spacing, we've got to look at all aspects, how much oil in place and thickness per zone and what kind of half like we think we're doing. Doing.
So specifically to Upton County, generally in most of the zones where we're at in Upton, the pay is a little thinner in both the Wolfcamp B and in the Lower Spraberry. And we've drilled a lot of Wolfcamp B wells down in Upton County. We actually did that on 8 80 foot spacing and just because the B was centered there and we thought we had a fairly good frac barrier. And as we look back on it, we really haven't seen any interference down in Upton County in the B. And so maybe we should have developed that a little tighter than we did.
So as we've got one lower spray very well enough and we've just completed 2 more. We'll have some results on in a few months. Now we drilled those at 6 60 foot spacing. So we'll test a little tighter spacing down in Upton in the Lower Spraberry than we did in the B and we'll just see how the results work out. As we look at the lower spray beer 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'll test tighter spacing there early on in those areas to guide us on what our ultimate development
That
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're talking about our hedge, Ron, our hedge volumes or how much production we had?
No, but again on the hedges and I can kind of see that you guys hedge at different pricing points.
I guess I'm just kind of trying
to think about the physical market and kind of your ex hedge volumes, where all that's going and what sort of pricing you're getting there conceptually?
Yes. We got 8,000 barrels a day to go to Magellan LongHorn down to Houston Ship Channel and that receives LLS pricing. All the remaining barrels we produce at this point go to Cushing Oklahoma.
That's it for me. Thank you.
Thank you. At this time, I'm 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.
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