Good day, ladies and gentlemen, and welcome to your Diamondback Energy Inc. And Viper Energy LP Joint Operations Update and 15 Guidance Call. At this time, all participants are in a listen only mode. Later, we'll have a question and answer session and instructions will follow at that time. As a reminder, this conference call is being recorded.
I would now like to introduce your host for conference call is being recorded. I would now like to introduce your host for today's conference, Adam Lawlis, Investor Relations.
Please go
ahead, sir. Thanks, Nova. Good morning, and welcome to Diamondback Energy and Viper Energy Partners Joint Operations Update and Guidance Conference Call. Representing Diamondback today are Travis Stice, CEO and other members of our executive team. During this conference call, 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. Good morning and thanks for joining us today as we host our call to provide an update on our accomplishments in 2014 and discuss Diamondback and Viper's plans for 2015. Before we get started, I'd like to commend my leadership team and organization on their continued ability to execute during the past 2 years as a public company, in which we've grown production an average of over 150% per year. I'm honored to be surrounded by such a dedicated team and I'm confident they will continue to excel through whatever challenges and opportunities we encounter this year. 2014 was another exciting year as we continued our track record for best in class execution and cost optimization and demonstrated the tremendous potential for Lower Spraberry development across our acreage in our initial wells.
Diamondback's production grew 166 percent in 2014 as compared to 2013, surpassing the approximate 150% growth we experienced in 2013 and above the high end of our 2014 guidance, which we had revised upward twice. As mentioned in our Q3 call, we're extremely excited about the Lower Spraberry potential across our acreage position and continue to see results that exceed expectations. We believe that the U. L. Taney 812 Unit 1 LS, Diamondback's 1st Lower Spraberry well in Andrews County and the Maybe Breedlove 2,301 LS mentioned on the Q3 20 14 conference call together derisk the Lower Spraberry in a large portion of Northwest Martin County and Northeast Andrews County.
We are also pleased with the performance of the Gridiron 2 LS, which was part of our first operated stacked lateral test and continues to show strong performance. 6 of the Lower Spraberry completions in the Q4 of per well from an average lateral length of 5,900 feet. Although we don't have a 30 day rate yet for these wells, early results are certainly encouraging. The Estes B Unit 1602 LS, our 1st Lower Spraberry well in Dawson County, just started producing oil prior to being shut in due to the recent severe weather. We expect to have results from this well with our 4th quarter 2014 earnings release.
4Q 2014 production for Diamondback increased 25 percent to 25,700 barrels a day equivalent from 20,600 barrels a day equivalent in the 3rd quarter. Both Diamondback and Viper exceeded their full year 2014 guidance ranges. Severe weather 2014 and early January of this year caused substantial production interruptions throughout the Permian Basin for area operators including Diamondback. While the impact was minimal in 2014, the company is still quantifying the 2015 volumes that were shut in due to lack of oil marketing or power. In the Q4 of 2014, Diamondback completed 19 gross horizontal wells, bringing the year to date total to 65.
4th quarter completions consisted of 10 Lower Spraberry wells and 9 Wolfcamp B wells. Looking ahead into 2015, we've outlined production guidance for Diamondback of between 26,000 and 28,000 barrels a day, which represents an increase over 2014 of approximately 40% at the midpoint. 4,200 to 4,500 barrels a day of this is expected to come from Viper. Diamondback's production guidance is based on a range of 2015 CapEx of between $450,000,000 which represents approximately a 40% reduction from our initial plans to run 8 rigs during the year. In February, we plan to release 2 horizontal rigs and our remaining vertical rig.
We plan to operate 3 horizontal rigs for the remainder of the year with 2 of the rigs at Spanish Trail where Viper owns the underlying minerals. We expect to drill and complete between 5060 gross horizontal wells in 2015, which at the midpoint represents approximately a 30% reduction from the 80 gross wells drilled in 2014. We anticipate that service costs will recalibrate to the current commodity environment and expect cost of $6,200,000 to $6,700,000 for 7,500 foot lateral horizontal well. With oil prices now less than half of what they were at the peak this last summer, we believe service costs should also decline from those highs. We are aggressively pursuing cost reductions and anticipate an overall reduction of at least 20%.
Currently, we've seen approximately 10% in reductions, but frac spreads have been slow to respond due to the backlog of completions. Approximately 10,700 barrels a day of Diamondback's 2015 production is hedged with the combination of Brent, WTI and LLS fixed price swaps at an average of $88.14 a barrel. Assuming that WTI stays flat at $50 this year, we continue to expect to become cash flow positive in the second half of twenty fifteen with the total outstanding borrowings under our credit facility of under $300,000,000 Diamondback's focus this year is on capital discipline, stockholder returns and maintaining a strong balance sheet. With our focus on returns, we'll continue to drill where the returns are the highest and intend to operate 2 horizontal rigs in Spanish Trail this year on our Viper owned minerals. Diamondback remains committed to looking for opportunities to expand its business through accretive transactions, not only through acquisitions, but also through drill to earn and other joint venture opportunities.
However, we will not do a dilutive deal simply to get larger. I believe that Diamondback remains an attractive investment as a low cost producer in the highest return basin. Operator, please open the lines up for questions.
Our first question comes from the line of Michael Rowe of TPH. Your line is
just wondered if you could perhaps walk through your anticipated production cadence throughout the year and maybe specifically quantify what the exit to exit growth rate is from year end 2014 to year end 2015?
Michael, we plan to kind of moderate our spending through the year in reflecting what we anticipate cost savings to be particularly around the pressure pumping size of our business. So while I've always had an extreme focus on how quickly we get these wells on production, since we've not seen the true cost reduction on the pressure pumping side, we're I wouldn't say we're slowing down, but the intensity on getting those wells brought online is a lot slower a lot less than it was this time last year because we fundamentally believe there's going to be a recalibration of costs. So it's a little difficult to kind of give you quarterly guidance. In fact, we don't typically do that. But when you look at sort of exit over exit, we'll be flat to slightly up on a year over year basis.
Okay. That's helpful. And I guess given the continued strong performance from your Lower Spraberry wells, do you envision that your reserve engineers could look to increase your 2 stream type curve by the end of the year when they're looking through the reserve report?
Yes. Michael, we're in the process right now of getting a finalized report from Ryder Scott. And certainly we anticipate very favorable uptick in the Lower Spraberry type curve. I think I communicated during our 3rd quarter call that performance from the wells that we brought on were exceeding the Ryder Scott type curve by somewhere between 35% 40%. So we'll get the finalized report here in a week or so.
And then when we do our 2014 wrap up and 4th quarter earnings call sort of in that mid February time frame, we'll have that finalized report and we'll give you an update of not only all the type curves, but also the total reserve picture for the company year over year.
Great. And just maybe one last question if I could would just be do you plan on directing any capital to your newly acquired Western Glasscock acreage in 2015? And if not, I guess what are your near term goals with respect to that acreage position? Thank you.
Well, that acreage block in Glasscock County was has minimal drilling obligation, will be essentially held by production. So the drilling activity we'll do in that area will be limited in 2015 unless commodity cock acreage.
Thanks very much.
Thanks, Michael.
Our next question comes from the line of Dave Kistler of Simmons and Company. Your line is open.
Good morning, guys.
Good morning, Dave.
Real quickly, I want to applaud you guys for being early to adjusting all these things. So very well telegraphed on what you were doing. But looking forward, as you think about service cost declines or you think about where commodity prices settle out, is there any kind of indication of where you could give us numbers in terms of where activity might accelerate again or inversely where activity may continue
to even slow further?
Yes, Dave. Obviously, that's a multivariate analysis there that we go through almost every day to try to figure that out. But in a general sense, I think total well costs need to come down more than 25% and commodity price needs to increase to between $60 $70 a barrel in the second half of the year before you'd Diamondback making a material change in our development scenarios. And I think what was the second part of that question?
No. That you covered it. You covered it. Obviously, there's a downside case as well where you'd continue to cut more.
The downside case Dave would be certainly below where we are right now $45 a barrel. But one of the things that I know you're well aware of is that we can still generate extremely positive rates of returns at very low prices, particularly in Spanish Trail where we're going to keep those 2 horizontal rigs working because of our ownership of Viper Energy Partners. Even at sub-forty dollars oil prices, we're still generating significant double digit returns on those investments.
Great. Appreciate that. And then just one other one. When we think about Viper and I look at the production guidance on Viper versus your all's production guidance for 2015, there's a little bit of a disconnect. Now I realize you're not the only operator in that's drilling wells with Viper.
Is that
conservatism in terms of what the
outlook might be for either give me on why there's a slight disconnect
there? Yes. Primarily it's because in this extremely depressed commodity price, we're not real sure how other operators are going to continue to develop that acreage. And so we did dial in a little bit of conservatism on the Viper side particularly in order to address that uncertainty. It's a little bit different on the Diamondback side where we have a greater certainty of activity levels.
Sure. I appreciate that. Thank you guys so much for the clarification.
Thank you, Dave.
Our next question comes from the line of Gordon Douthat of Wells Fargo. Your line is open.
Thanks. Good morning, everybody. Just trying to get a handle on the cost side of the equation here. And Travis, you mentioned the completion backlog is kind of preventing the pressure pumping side of from coming down? And where do you see that in the Permian that completion backlog?
And when do you see things start to turn there?
Yes, we're probably a quarter. It's probably going to take the rest of this quarter. But to give you an idea of where we are on that, if you look at this time last year, WTI was somewhere between $90 $95 a barrel. Today, it's obviously more than half that much. It cost me 15% more almost 15% more to frac a well today than it did January of last year at $95 oil.
And so that's the disconnect and that's the recalibration that I think we've got to have. But I understand on the service side from the pressure pumping guys particularly that they've got a full frac schedule for another several months and it won't be until that frac schedule gets worked off and iron gets stacked in the yard that you see the recalibration that the industry so desperately needs.
Okay. And then just trying to get a handle on the well cost side. So it looks as if your targeted costs are coming down. Just trying to get a sense of where your current costs are within kind of the framework where you said in the press release that the costs are down 10%, but do you expect further reductions? So are we kind of midway through that progression, I guess?
Yes. I think you're actually only about a quarter of the way through that progression. I think the back half of the year certainly if commodity prices stay below $50 a barrel, you're going to see massive reductions in overall service costs.
Okay. And then just last one for me. How do you look at the Lower Spraberry versus Wolfcamp in 2015? Where how do you it looks like half your activity in the Q4 was kind of split between them evenly. How do you look at that split going forward?
Yes. Diamondback has always communicated that we always put the drill bit in the highest rate of return zones that we can. And that's been our mantra now for 2 years. And obviously, the Lower Spraberry has a much higher rate of return. So our program in 2015 is going to be more weighted towards Lower Spraberry.
That being said though as we look at the complexities associated with multi stacked zone development, we recognize that we're going to have to develop some of these zones at the same time we do the Lower Spraberry. So if you're trying to kind of get a model in there somewhere between 60% 75% of the wells in 2015 will be in Lower Spraberry with the remainder in the Wolfcamp B.
Okay. Thanks a lot.
Thank you. Our next question comes from the line of Tim Rezvan of Stern AG. Your line is open.
Good morning, folks. Travis, I was hoping you could put your Viper hat on and talk about what you all are seeing in terms of trying to pick off more mineral rights? What the commodity price reduction has done on that front?
Well, Tim, we've discussed before that I typically don't give any guidance on ongoing acquisitions. But I can tell you in a general sense that Viper is fully engaged in the marketplace of trying to acquire additional minerals. I think the commodity downturn has impacted those guys that were looking for cash in the transaction, but it has heightened the awareness mineral owners divesting or converting their ownership into Viper units. So while we've while you might see at least on larger deals the cash transactions sort of taken a pause. We're seeing a significant uptick in interest in intake in Viper units.
So it's just something that we're working really hard on and it's like most acquisition programs and you could go several quarters without any activity and then all of a sudden you get several deals that come together during 1 quarter. So just for the Viper unitholders, we're fully engaged at looking at additional opportunities.
Okay. I appreciate that color. And then on the backlog of wells in the Permian, do you have any view or any insight on what that backlog is like as far as horizontal rigs across the Midland Basin? A big bear case on oil is that we there will be an enormous lot that will take much of 2015 to work through kind of uncompleted wells. I mean any insight you could give on what you see in the Midland Basin would be helpful.
Well, certainly, I can't with any kind of degree of accuracy predict what the whole Permian Basin is going to do. But I'll tell you it's probably a quarter to maybe a little a quarter and a half that's going to take the industry to work off that backlog. But I do think you'll see the rig response a lot faster for those operators that have the ability to drop those rigs. You'll see that occurring on a week over week basis as you look at rig count metrics.
Okay. Thank you.
Next question comes from the line of Jeff Grampp of Northland. Your line is open.
Good morning, guys. Great job with everything. I was just hoping to get maybe some incremental color on the Dawson County Lower Spraberry well. I know you don't have much if any production data, but any kind of color on maybe what you guys saw through the drilling or completion process or just any early data you guys are willing to share at this point?
Yeah. From the drilling and completion perspective, you don't really see a lot of difference in rate of penetration or even the frac gradients. You don't see a big difference when you stimulate the wells. And really, Jeff, we had just got that well on maybe a couple of weeks before we lost power for that whole part of the county up there. And we've got a sub pump in the well and it just started cutting oil.
And what 2 days ago, 3 days ago, we just got it back on. And so the headway that we've made in pulling water out of the formation from that we placed in there from the frac, we've got to regain that ground. And so I should with a lot of clarity be able to give you some insights in our February call as to how that well is performing.
Okay. And then just maybe kind of building off of another analyst question regarding type curves and then maybe tying that into 2015 production guidance. Are you guys assuming maybe or kind of building in recent performance from a lot of your wells? Are you guys maybe using more of the backward looking type curves that you guys previously conveyed to the street?
I think when we release the reserve report here in a month or so, you should expect an uptick in the Lower Spraberry wells. But the Wolfcamp B wells, we're going to we'll probably stay real close to what we had in 2014.
Okay. Well, maybe if I can just kind of ask my question a little bit differently. In terms of what's baked into the 2015 guidance, is that more based on the Lower Spraberry wells you guys have out there? Or is that maybe building in some uptick from some of the recent performance you guys have been seeing?
Yes. It's matching recent performance, Jeff.
Okay. Got you. And then if I can just sneak one more in. Just kind of wondering about how you guys are looking at lateral length. Obviously some real nice kind of low decline rates on some of these longer laterals.
Is that are you guys attributing that to that longer lateral or are there some other things going on there or just kind of wondering to get some insight on how you guys are looking at lateral lengths going forward?
Yes. We still make the decision on lateral lengths by and large based on lease geometry. So we believe that somewhere we're a lot more comfortable with 10,000 foot laterals than we were 2 years ago when we started drilling horizontal wells. There's still operational risk associated with those longer laterals, particularly in Lower Spraberry because the reservoir pressure and the energy that you need to clean out those laterals post frac is not as high as you see in the other intervals. So if you try to pin me down, I'd probably say the Lower Spraberry, while we like the capital efficiency associated with longer laterals, we've got to address some of the other issues operationally about getting those wells drilled out and cleaned out.
A lot of our wells in 2015 in the Wolfcamp formation will be in that 8000 to 10000 foot lateral length. And certainly, we've demonstrated excellence in drilling them at that length. And also the completion guys are much more comfortable cleaning those wells out post frac as well. So longer is better, better capital efficiency, higher rate of return. And where we have lease geometry that allows for that.
That's our intentions.
Okay, great. Thanks. Great job with everything guys. Thank you,
Our next question comes from the line of Jason Wangler of Wunderlich Securities. Your line is open.
Good morning, Travis. Thanks for all the color. The only other thing I was just kind of curious about is you talked about the 2 rigs in your Spanish Trail area. Where is that other rig kind of going to float around? Do you have any kind of insight on that side?
Yes. Jason, you said it just right. It's a floater rig. We'll stay in the areas that have lease obligations that have the highest rate of return and we'll honor all of our obligations in 2015 with that one floater rig. So we'll maintain our acreage position and we'll float that rig around, but primarily in Northeast Andrews and Northwest Martin County and Southwest Martin County.
Okay, great. And then you kind of maybe already answered it, but just as far as the holding acreage and things that's basically that's rigs job so to speak as far as going through 2015 keeping all the
acreage that you guys have had that you guys
have been picking up the last few years?
That's correct. Yes, we'll maintain all of our lease obligations.
Perfect. Thank you. I'll turn it
back. Thank you. I would now like to turn the program back to Travis for closing remarks.
Thanks again for everyone to participate.
Sir, we do have one further question.
Sure.
Okay. We have a question from the line of Welles Fitzpatrick of Johnson Rice. Your line is open, sir.
Hey, good morning guys. Sorry to hop in there at the last second. So it sounds like you're looking for 20, 20 plus pricing related savings at some point in the year. Should we be expecting an acceleration of the efficiency savings that you guys have been seeing as you're running a lighter and somewhat more concentrated program?
Yeah. That optimization effort goes on every day regardless of commodity price. We always try to drill and complete these wells better, cheaper and faster than we did the prior well. So that optimization effort and those efficiency gains, we continue to see on a day to day basis and I fully expect them to be realized in 2015 as well. One of the things wells that I think is important is that about 3 quarters of our wells in 2015 will be drilled on multi well pads.
And there's inherent cost savings associated with the efficiencies of multi well pads. And we've tried to dial that into our expectations, but I anticipate that accelerating throughout the year as well.
Perfect. And just one more and I'm sorry if I missed it, but did you guys give a Wolfcamp Lower Spraberry and kind of other split of that 50 to 60 gross wells in 2015?
Yes. About 2 thirds to 3 quarters of the wells in 2015 will be drilled in Lower Spraberry and the remainder will be in the Wolfcamp intervals.
Perfect. Thanks so much.
You bet, Will. Thanks.
Our next question comes from the line of Steven Carpool of Credit Suisse. Your line is open.
Good morning, guys.
Hey, good morning, Steven.
You alluded to it a bit on efficiency and what you're going to do on rate of return certainly in Spanish Trail. But what does it take for you to do to go back and drill a vertical well? If you look at where costs come down, what changes or maybe where costs are or maybe it's a price to start thinking about what you do on your acreage?
Stephen, you've been a part of the Diamondback store for a couple of years now. And you know that right after the IPO, we shifted the whole company strategy away from vertical wells and that strategy hadn't changed. The only time we're going to drill vertical wells is where I can't address a lease obligation issue with the horizontal well. So there's really very based on the higher rate of return, based on capital efficiency and finding cost, our capital deployed is always better using horizontal wells than vertical wells. So I've let a horse I've only had one essentially one, maybe 1.5 vertical rigs working in 2014 and it's on its last well right now.
And we'll just barely pick it up maybe for a couple of wells this year that address obligations that I can't get done with the horizontal well.
Since you mentioned the obligations, you alluded to it a bit with I think the use of the Viper units as well. Is there how much of an issue you think it is for other operators? And how much of an opportunity is it for you to be able to take over others' obligations? Does that become a real opportunity yet? Or is it are we still a little ways away?
Well, we always like I mentioned in my prepared remarks, we're always opportunistic for looking to do an accretive deal. And whether that accretive deal takes the form of drilled earns or other JV type structures, we're actively out in the marketplace looking for those things. I'll probably say that the bulk of those opportunities are still in front of us, would be my guess based on the prolonged lower commodity price and potentially recalibration of folks borrowing base in the Q2 that may create some more opportunities for us.
Thanks, Travis.
You bet, Steven.
Ladies and gentlemen, that concludes our question and answer session for today. I'd like to turn the call back to Travis Stice, CEO. Sir, the floor is yours.
Thank you. And again, thanks everyone for participating in today's calls. If you have any questions, please reach out to us using the contact information provided. You all guys have a great day. Thanks a bunch.
Ladies and gentlemen, thank you for participating in today's conference. You may now disconnect. Everyone have a wonderful day.