Good day, ladies and gentlemen, and welcome to Diamondback Energy Second Quarter Earnings Call. At this time, all participants are in a listen only mode. Later, we will conduct a question and answer As a reminder, today's call is being recorded. I would now like to turn the conference over to Adam Lawless of Investor Relations. Sir, you may begin.
Thank you. Good morning, and welcome to Diamondback Energy's 2nd quarter conference call. Representing Diamondback today are Travis Stice, CEO Tracy Dace, CFO and Russell Panamil, VP of Reservoir Engineering. 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. During our call we will reference certain non GAAP financial measures, which we believe provide useful information for investors. We include reconciliations of those measures to GAAP in our earnings release. I will now turn the call over to Travis Stice.
Thank you, Adam. Welcome everyone and thank you all for listening to Diamondback's Q2 2014 conference call. Since our last call, we've issued an operations update that highlighted our pending leasehold acquisition primarily located in Midland and Glasscock Counties in the core of the Northern Midland Basin, increased our full year production guidance, successfully completed our southernmost test of the Lower Spraberry in Upton County, and that we have placed on production the best horizontal well on a per lateral foot basis in the Midland Basin. Switching to 2nd quarter results. We have completed we've continued our production growth by growing volumes over 170% as compared to the Q2 of last year and 32% from the prior quarter.
We continue to expect to grow production by nearly 150% in 2014 as compared to 2013. This would mark the 2nd consecutive year of nearly 150 percent production growth. Our operating expenses continue to be within guidance, but with nearly 300 gross vertical wells acquired this year, we would expect cost to migrate towards the high end of guidance in the near term as we optimize these wells consistent with our prior practices. Our low op cost structure combined with high oil cuts continue to drive peer leading cash margins. We have several significant wells in various stages of throughout our leasehold in the Midland Basin.
We've drilled our 1st Lower Spraberry well in Martin County, our 1st Klein well in Dawson County, and our first stacked Wolfcamp B Lower Spraberry well offsetting our gridiron well in Midland County. All are awaiting completion operations to begin in the next several weeks. Additionally, we are testing increased frac density in Midland County on 2 adjacent 5,000 foot lateral wells using our standard 22 stage design on 1 and an increased density frac design of 33 stages on the other. Expect further details on these well results in the upcoming quarters. Finally, we've drilled and completed our first three well Wolfcamp B pad in Upton County, realized savings of $1,250,000 to 1.5 $1,000,000 bringing the total drilling and completion cost for all three wells to $15,300,000 or $5,100,000 per well for a 5,000 foot lateral, our lowest cost to date.
From spud of the first well to TD of the third well, operations took 38 days. We're also currently drilling our first three well Lower Spraberry pad on our Spanish Trail lease in Midland County. As we continue to increase pad drilling, we expect some production lumpiness going forward as we conduct simultaneous operations on pad wells. Adding a final point on execution, we have drilled a 10,000 foot lateral in Upton County with a total measured depth of 19,353 feet in a record 14 days. We've now drilled over 80 horizontal wells in the Midland Basin and I'm pleased we're still setting records.
As exciting as the growth story has been and continues to be since our IPO, we're also excited about our growth in 2015 and beyond. We're currently running 2 horizontal rigs on our Spanish Trail lease in Midland County and 1 each in Andrews, Martin and Upton Counties. We expect to add a 6th horizontal rig in our existing acreage in early Q1 of 2015 as well as a 7th horizontal rig on our recently acquired acreage. We also plan to add an 8th horizontal rig in the second half of twenty 15 and are contemplating adding a 9th in 2016. Turning to well results, our Neal Lower Spraberry well in Upton County had a 30 day rate of nearly 7 50 BOEs a day from a 6,800 foot lateral on ESP, which is as good or better than our average Wolfcamp B wells in Upton County, setting us up for additional years of drilling in this asset area.
In Midland County, the Spanish Trail Northwest 25-1 Lower Spraberry had a 30 day rate of 8 59 barrels a day from a 4,400 foot lateral on ESP. We completed our 2nd successful Clear Fork Shale well in Andrews County with a 30 day average rate of 4 73 BOEs a day from a 7 200 foot lateral, which is 15% to 20% higher than our initial well. Well cost in this Clear Fork will trend towards $6,000,000 for 7,500 foot lateral, enabling development costs to compete with other investment opportunities in our portfolio. Our second and third Wolfcamp B wells in Northern Midland County posted positive results with a 30 day naturally flowing average of 6.84 BOEs a day combined from an average lateral length of 7,300 feet. These wells typically don't reach peak production until placed on artificial lift, which we will likely do this month.
Early results from these two wells are at or above results seen from our initial well. As a reminder, we report our well results on a 2 stream basis. While we continue to be active in the acquisition arena, we maintain our disciplined approach to evaluating deals. I've consistently communicated that we will do only accretive deals and each acquisition is evaluated in relation to the stock price we would receive for financing each opportunity. We firmly believe the greatest long term shareholder value is created through consistent application of this discipline.
When you couple this strategy with existing best in class execution and organic growth, you have a winning combination with Diamondback. With these comments complete, allow me to turn the call over to Tracy.
Thank you, Travis, and welcome, everyone. I'll provide a quick overview of the financial highlights. Our net income for the Q2 was $27,800,000 or $0.54 per diluted share versus net income of $14,500,000 or $0.36 per diluted share for the same period in 2013. Adjusted net income for the quarter included a loss on commodity derivatives of $11,100,000 and a loss on sale of assets of $1,400,000 Excluding the losses and the related income tax effect, our adjusted net income was $35,800,000 or $0.70 per diluted share. As previously reported, our production for the 2nd quarter was approximately 17,836 BOE per day.
These volumes generated revenues in the Q2 of $127,000,000 compared to $45,000,000 for the same quarter in 2013. Realized pricing for the Q2 before the effect of hedges was $78.25 and with the effect of hedges, it was 70 $6.02 Our average realized oil price before hedges was 95 with the effect of hedges, it was $92.20 Our EBITDA for the quarter was 103,000,000 Turning to costs, our LOE was $6.47 per BOE in the 2nd quarter. Our general and administrative costs came in at 2.42 dollars per BOE, which includes non cash stock based compensation. Excluding stock based compensation, G and A costs were $1.73 per BOE. Our current hedge positions through 2015 have been laid out in our earnings release.
We currently have about 40% of our estimated crude oil production hedged for the remainder of 2014. We continually assess our hedging opportunities and we intend to continue to layer on additional hedges as our production grows. In the Q2 of 2014, we generated $87,000,000 of operating cash flow and $85,000,000 of discretionary cash flow or $1.70 $1.66 per diluted share respectively. During the Q2 of 2014, we spent $124,100,000 for drilling, completion and infrastructure. Our liquidity position remains strong with approximately $37,000,000 of cash on hand at June 30, 2014 and we had drawn $46,000,000 on our secured revolving credit facility, which had a borrowing base of $350,000,000 We have subsequently reduced the outstanding balance to 0 with a portion of the proceeds from our equity offering in July.
I'll now turn the call back over to Travis for his closing remarks.
Thank you, Tracy. To summarize, we are again adding acreage in the core of the North Midland Basin play and we've recently increased production guidance for the 2nd time this year. I'm proud of our continued success in driving production growth, continued improvement executing on these complex well pads and confirming new zones like the Lower Spraberry in Upton County and Fork Shale in Andrews County. I believe we continue to deliver results and stockholder returns that are among the best in the Midland Basin. Before I open the call for questions, I want to acknowledge our employees and all they've accomplished in the first half of this year and especially welcome those employees that are new to Diamondback.
On behalf of the Board and employees of Diamondback Energy, I would like to thank you for your participation today. This concludes our prepared comments. Operator, please open the call to questions.
Thank Our first question is from Dave Kinstler of Simmons and Company. You may begin.
Good morning, guys. Good morning, Dave.
Real quickly, looking at the Martin County Wolfcamp B results and the Andrews County Clear Fork results, Can you talk a little bit about what that does for increasing development inventory on a longer term basis? And then where those might fall in terms of competing for capital as you go forward with development?
Sure, Dave, and thank you. I think in my prepared remarks, I actually referenced those Wolfcamp B wells in Midland County and of course they're in Northern Martin County. So I apologize for that misspeak there. But specifically on those Martin County wells now, this is the 2nd and third well and we're confirming kind of that reserve target of between 650,000 and 700,000 barrels of oil equivalent. And that's going to place these in that 50% to 60% rate of return.
So it's really time for us to go to work there now. We've got 3 wells that are spread across the acreage. It really confirms the viability of Wolfcamp B. So I think it's logical to assume that we'll park a rig there and really focus on well to well efficiencies. Now moving over to the Clear Fork Shale in Andrews County.
As I mentioned those well costs are going to be around $6,000,000 I actually think as we get in there with repeatable wells, we can drive those costs down. But as it sits right now with the $6,000,000 well cost, that Clear Fork Shale is going to be somewhere between 30% 40% rate of return and probably 450,000 to 500,000 BOEs on an equivalent basis. And while 30% to 40% rate of return is still a good well, it's certainly it doesn't compare when you look at the plus 70% to almost 100% rate of return including the effective minerals we get in Midland County. So don't expect us to get out there and just start drilling well one well right after another. But we've probably got about 50 to depending on spacing maybe over 50 locations in the Clear Fork Shale.
But what I think is more logical is that you'll see us early next year maybe late this year move back into there and drill a 2 well pad and see if we can get some cost efficiencies on the 2 well pad and improve the economics there.
Great. I appreciate that. And then maybe switching to something a little bit different. One of your peers recently contracted for a bunch of water sourcing looking forward and talked about what their water needs will be for doing completions over the next 10 years. Obviously, a ways away, but can you talk a little bit about how you're handling the water situation right now and how that factors into the rig ramp that you've outlined for us getting to kind of 9 rigs by 16?
Sure, Dave. What we've done is gone through each of our development areas and put in place what we call a water usage plan. And that water usage plan is sort of a holistic approach to access, accumulation and disposal of water. And we've really got to be effective in addressing each of those three things for each of our asset areas because once we have a real well laid out strategy for those three items, then we go in and put rigs on top of that. And I think we're going to need all sources of stimulation water going forward, whether it's existing freshwater, brackish Santa Rosa water or recycled water in order to match our rig needs.
So it's an issue that we've got that we're paying real close attention to and trying to make sure it's consistent with our development strategy.
Great. Appreciate that. And then just as long as we're on things that could be potential bottlenecks going forward, what are the other bottlenecks that kind of concern you as you look at this aggregated portfolio and how you develop it going forward?
Well, there's a lot of there's an impact in the journal yesterday, there was a nice article on sand and you're seeing more and more sand being used in our industry, whether it's in the Eagle Ford or the Bakken and even in our own backyard where we're talking about increasing a £6,000,000 job up to £9,000,000 job. To the extent that the industry migrates towards more and more sand in these horizontal wells, I think it's realistic that we've got to make sure we've got the full supply chain figured out to make sure we and our service companies can access the sand at the time we need it. And then between sand and stimulation water Dave, those are the two things that I think about.
Okay, great. I really appreciate the clarifications. Great work guys.
Thank you, Dave.
Thank you. Our next question comes from Gordon Faucette of Wells Fargo. You may begin.
Thanks. Good morning, everybody. Just to dovetail off of that last question. So recognizing it's a bit earlier in the Permian delineation, but there's been a lot of talk recently about evolution of completion designs. And since you mentioned thoughts about increasing proppant, how are you thinking about the evolution of your completion designs going forward?
Well, Gordon, we've always continued to tweak our completion designs, always looking for ways to extract more oil out of this rock at a competitive price. Just as an aside, I know there's a lot of communication in the industry now about the effect of slickwater fracs. Well, we did our first horizontal well over 2 years ago down in Upton County as one of the first operators to start drilling horizontal wells in areas that have been predominantly drilled vertically. And that first horizontal well was a slickwater job and that's really we've got over 80 of them completed and I think 79 of them have had a slickwater frac or applied to it. So we've continued to tweak sand per foot, water per foot.
And then in this most recent test, we're going to try to hold as many variables constant as we can and just increase the number of stages across the lateral and that's that 22 stage going up to 33 stage and we're doing it on a sister well. So it's a pad well and one well will do it with 22 stages and then just immediately over we'll do the next well with 33 stages. And we think that will give us the best way to measure our improvement. And it's going to it's about 3,000,000 more pounds of sand. It's probably going to cost us about 1,000,000 barrels.
But if we can pick up a little more $1,000,000 if we can pick up about 10,000 more barrels on EUR, it'll probably pay for it. So just look for us to provide more color as we go forward.
Okay. That's helpful. And then a question, Travis, you mentioned in your comments, prepared remarks that the rig allocation this year and as you add rigs next year, I'm just wondering how you look to allocate those rigs across the various areas of your position?
Yes. We talked in our operations a couple of weeks ago about on the newly acquired acreage. I think we'll have a rig and a half on that new acreage. So there's 1.5 rigs there. The other rigs, we're going to try to keep as many rigs as we can in our Spanish Trail acreage where Diamondback owns 90 3% of the minerals there now.
We'll try to keep as many there. We'll keep one rig down in Upton County. That's why I was excited about this new Lower Spraberry well that gives us some good opportunities there. 1 of our competitors talked about a nice client result down in Upton County as well, which we haven't tested yet, but obviously we'll take close attention to there. So 2, 3 Midland County, 2, 3 in the northern blocks, 1.5 in our newly acquired acreage and 1 or so down south.
We'll get you kind of into that 7.5 rig, 8 rig cadence.
And then under that program, any preliminary thoughts on how the growth profile will trend?
Gordon, we've not signaled yet what our 2015 is going to be. I think we have a November call scheduled and that's when we'll have a more fulsome discussion on 2015.
Okay. Thanks a lot guys.
Thank you, Gordon.
Thank you. Our next question is from Mike Kelly of Global Hunter Securities. You may begin.
Thanks guys. Good morning. Travis, I was hoping you could talk about the opportunity set for Viper. You guys are really kind of the first mover here with the middle rights in an MLP. So, assuming you could talk about that?
And then also curious if there's beyond just being a 92% owner of Venom, if there's any other added benefits that might not be obvious for FANG shareholders having that MLP in place? Thanks.
Yes. Thanks, Mike. Really on the Viper side, the council Yes. Thanks, Mike. Really on the Viper side, the council
has advised me to not be speaking too publicly
about the status of our acquisitions. I can tell you in a general sense, I've been really pleased with the amount of opportunities we've already had in the 1st 30 days. And I think just look forward to us providing more color on Viper in our upcoming calls. And specifically, again, we laid out the benefits to Diamondback pretty clearly during our IPO on Viper. And I think you can just refer back to our Viper web page and you can see all of those details.
Okay. Fair enough. And then with Viper, is there the desire to go outside of the Permian and look for deals? And does that ultimately mean Bang is obviously very Midland focused, you talked about ramping to 9 rigs there. Does that ultimately lead you to want to take Diamondback outside of the Permian as well?
Thank you.
You bet. Thanks, Mike. Well, specifically on Viper as we talked about during the IPO, Viper is not constrained to the Midland Basin. Obviously, Diamondback is laser focused on execution results in the Midland Basin. But the Viper level, we're looking for accretive deals in all the other basins.
And the 3 kind of criteria we're looking for are basins that are actively under actively being developed, oil weighted basins and the operator that's developing the minerals is a competent operator. So those are kind of the 3 broad focus items that we look at when we start screening deals for Viper.
Great. Thank you.
Thank you. Our next question is from Jason Wangler of Wunderlich. You may begin.
Good morning, guys. Just curious as far as you talked a lot about just different infrastructure and bottlenecks. Just curious on the frac side as you're seeing that one. Obviously, you keep ramping the rig count. The plan is to ramp it further later this year and in the next.
What are you seeing as far as frac and as far as the contracts that you may have now or what you may have to look at as you go forward?
Yes. We're continuing to see some cost pressures from the pressure pumping side of the business. One of the things that we're pleased with is that we've got 2 dedicated crews working for us right now and we've got roughly 40 or so wells to complete in the second half of this year. And of those 40, 30 of them roughly 30 of them will be on pads. And the efficiencies that I talked about in my prepared remarks on the cost side, a lot of that comes from the stimulation side because you've just got you can set a crew right there on the location and get 2 or 3 wells at one time.
And so I'm still trying to do everything I can to hold the line on cost and offset any increases in costs with improved efficiencies. But I do think that the tension is getting pretty tight now. We've got 2 dedicated crews as I mentioned and we're looking at maybe bringing a third dedicated crew on later this year early in Q1. One of the things that the stimulation companies have communicated to us is that they really like working for Diamondback Energy because even though like right now we're just running 5 rigs, it's really equivalent to running or working for another company that's running 8 or 9 or 10 rigs because of the how fast we get these wells drilled. So it really builds a doesn't builds a nice inventory of wells that they can just move through very quickly and that helps efficiency on their side and it helps on our cost side as well.
That's helpful. And then maybe just on the other side of it, as you get the oil out, I know that you're focused on the takeaway. How are you seeing that market playing out? I think there was a little bit of differential issues somewhat in the quarter at one point with the refinery down. But how are you seeing that market playing out so
far? We know that there's several large pipelines that are getting ready to either start filling or will here shortly in the second half of this year that ultimately that that differential blowout that occurred a couple of weeks ago, a month ago will come back into more traditional trading levels on that Mid Cush differential. We're continuing to look at space that's available on these other pipelines that are leaving the Permian that are not going to Cushing, Oklahoma. And just as a reminder, we've got 8,000 barrels of that gross that we've already committed and are moving right now on the Magellan Longhorn pipeline and we receive LLS pricing for that. So any incremental barrels above 1,000 barrels a day have been subjected to that mid Cush differential, but at least we've got a little insurance for our stockholders on 8,000 barrels a day.
And we're looking to look get more space on pipelines away from Cushing, Oklahoma to try to address that issue.
Great. I'll turn it back. Thank you.
Thank you. Our next question is from Jeffrey Connelly with Mizuho Securities. You may begin.
Hi, guys. Thanks for taking the questions. You mentioned in the prepared remarks production might be a little lumpy due to a lot of wells on pads. Can you give us any color on the completion schedule in the 3rd Q4 that might help us model production?
Yes. As I just I was just talking with Jason there. I think we've got 40 wells that we've kind of scheduled between now and the end of the year. And with 2 full dedicated crews right now, it ought to be in that 20 ish wells per quarter. And again, we've got to have a little flexibility in that.
But in order to get our annual guidance of wells completed, we need to be in that 20 wells per quarter and that's where we've got it laid out right now.
All right. Thank you. That's helpful. I'll jump back in the queue. That's it for me.
Thanks, Jeff.
Thank you. Our next question comes from Welles Fitzpatrick of Johnson Rice. You may begin.
Good morning.
I know that you guys have hit on this a little bit, but the majority of your wells going forward should be on at least 2 well pads. Can you talk about any potential to accelerate or to make those 3 or even more wells per pad? And then also the availability of walking rigs where you
are? Yes. I'll answer those in reverse. The walking rigs, we try to have about half or three quarter of our rig fleet available for that walk from well to well. For example, that 3 well pad that we talked about down in Upton County, that rig was set up with walking feet and it moved from well to well in less than 8 hours.
Typically takes us 2, 2.5 days to move a rig. And so on a 3 well pad, we moved them in 8 hours. And about half to 3 quarters of our rig fleet will be set up to do that. We also because we still are geographically diverse, we need to have these rigs that are quick to move a minimum number of loads and then can move from area to area. And so I can't have all of my rig fleet that are set up all of my rig fleet that are set up with feet, because I need those fast moving rigs.
So out of the and I'll look to Mike here real quick. But out of the 6 rigs we'll have at the end of this year, Mike, how
many of those will be set up with rig feet? You'll have 4 with rigs with the walking feet and you'll have 2 that are H and D rigs that are quick movers. And spud rig release to spud times, you're looking at the 2.5 to 2.8 days for the H and P rigs and a full pad with the logging feet to move from pad to pad is about 3.5 days from 1 of the big 1500 horse rigs with the feet. And then as Travis mentioned between wells, it's about 8 hours. Actually spud rig release to spud will run you a little about 0.8 days on a pad where we can walk the rig from 1 to 10.
Thank you, Mike. Yes. Perfect.
And then just one more sort of in the same vein. It seems like those cost savings per well were a little bit higher than expected. But should we think about that as generally shifting towards the lower end of you all's 9.6 to 7.4 completed well cost range? Or should we think of it as actually shifting that range?
Well, I wish that had I wish I could tell you that with the shift in the range lower what I think it may end up doing is offsetting some of the cost increases that we're seeing. So at this point, I don't want to signal that we're going to be lowering our range on per well completions.
That's perfect. Thank you so much.
Thank you. Our next question is from Joseph Krieger of ROTH Capital Partners. You may begin.
Good morning, guys. Most of my questions have been answered, but just one key point is with all the water supply issues that have been going on in many of the basins, how are you guys planning ahead for this with the additions of up to 3 more rigs over the next 18 months?
Well, Joe, I talked a few minutes ago about our water usage plan for each area and a little bit more detail on that when it comes to access and accumulation. That means it's the number of fresh water or brackish water wells that we drill in advance of the drilling rig arriving. And it also means we've got to size appropriately our storage frac pits for these types of water. So that's what we're doing. We're in the on the newly acquired acreage, we're rapidly coming up with a water usage plan that gets all the way to the how prolific the brackish water wells are, how prolific the freshwater wells are and then what size frac ponds we need to accommodate our rig schedule.
And that's I think I had a previous question about increasing from 2 to 3 well pads. And ideally, we'd like to stay with 3 well pads, but some of that hinges on our ability to accumulate water and also lateral length as well too. The longer laterals also require obviously more stimulation fluid. So it takes a little longer to accumulate that amount of stimulation fluid.
Okay. And do you guys have an idea of what kind of relative cost inflation impact the water supply situation has had on you guys over say the last 12 months?
Yes. I wouldn't say that the water supply has impacted the cost. What I would say is that it's more on the pressure pumping side. The hydraulic horsepower charges that we're seeing are working their way up. Really the only difference on the stimulation fluid is that when we drill these brackish wells, they're a couple of $100,000 a piece as opposed to a freshwater well, which is $10,000 to $20,000 a piece.
Okay. Thank you.
Thank you. I would now like to turn the conference back over to Travis Stice for closing remarks.
Thank you. Thanks again to everyone participating in today's call. If you have any questions, please reach out to us using the contact information provided.