Good day, ladies and gentlemen, and welcome to the Diamondback Energy second quarter earnings call. At this time, all participants are on a listen-only mode. Later, we will conduct a question and answer session, and instructions will follow at that time. If you require any assistance during the call, please press star and zero on your touchtone telephones. As a reminder, today's call is being recorded. I would now like turn the conference over to Adam Lawlis of Investor Relations. Sir, you may begin.
Thank you. Good morning, welcome to Diamondback Energy's second quarter conference call. Representing Diamondback today are Travis Stice, CEO; Tracy Dick, CFO; and Russell Pantermuehl, 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 today, 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, thank you all for listening to Diamondback's second quarter 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, we have placed on production the best horizontal well on a per lateral foot basis in the Midland Basin. Switching to second quarter results, we've continued our production growth by growing volumes over 170% as compared to the second quarter 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 second consecutive year of nearly 150% production growth.
Our operating expenses continue to be within guidance, with nearly 300 gross vertical wells acquired this year, we would expect costs 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 development throughout our leasehold in the Midland Basin. We've drilled our first Lower Spraberry well in Martin County, our first Cline well in Dawson County, 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 two adjacent 5,000-foot lateral wells using our standard 22-stage design on one 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 $1.25 million-$1.5 million, bringing the total drilling and completion cost for all three wells to $15.3 million, or $5.1 million 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 are currently running two horizontal rigs on our Spanish Trail lease in Midland County and one each in Andrews, Martin, and Upton counties. We expect to add a sixth horizontal rig in our existing acreage in early first quarter of 2015, as well as a seventh horizontal rig on our recently acquired acreage.
We also plan to add an eighth horizontal rig in the second half of 2015 and are contemplating adding a ninth in 2016. Turning to well results, our Neal Lower Spraberry well in Upton County had a 30-day rate of nearly 750 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 859 barrels a day from a 4,400-foot lateral on ESP. We completed our second successful Clear Fork shale well in Andrews County with a 30-day average rate of 473 BOEs a day from a 7,200-foot lateral, which is 15%-20% higher than our initial well.
Well cost in this Clear Fork will trend towards $6 million 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 684 BOEs a day, combined from an average lateral length of 7,300 ft. 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 two-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 second quarter was $27.8 million or $0.54 per diluted share, versus net income of $14.5 million 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 $11.1 million and a loss on sale of assets of $1.4 million. Excluding the losses and the related income tax effect, our adjusted net income was $35.8 million or $0.70 per diluted share. As previously reported, our production for the second quarter was approximately 17,836 BOE per day. These volumes generated revenues in the second quarter of $127 million, compared to $45 million for the same quarter in 2013.
Realized pricing for the second quarter before the effect of hedges was $78.25, and with the effect of hedges, it was $76.02. Our average realized oil price before hedges was $95.19, and with the effect of hedges, it was $92.20. Our EBITDA for the quarter was $103 million. Turning to costs, our LOE was $6.47 per BOE in the second quarter. Our general and administrative costs came in at $2.42 per BOE, which includes non-cash stock-based compensation. Excluding stock-based compensation, G&A costs are $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, we intend to continue to layer on additional hedges as our production grows.
In the second quarter of 2014, we generated $87 million of operating cash flow and $85 million of discretionary cash flow, or $1.70 and $1.66 per diluted share, respectively. During the second quarter of 2014, we spent $124.1 million for drilling, completion, and infrastructure. Our liquidity position remains strong, with approximately $37 million of cash on hand at June 30th, 2014, and we had drawn $46 million on our secured revolving credit facility, which had a borrowing base of $350 million. We have subsequently reduced the outstanding balance to zero 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 Northern Midland Basin play. We've recently increased production guidance for the second time this year. I'm proud of our continued success in driving production growth, continued improvement executing on these complex well paths, and confirming new zones like the Lower Spraberry in Upton County and Clear 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 on 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 you. Ladies and gentlemen, if you wish to ask a question at this time, please press the star and number 1 key on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. Our first question is from Dave Kistler of Simmons & 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. Specifically on those Martin County wells, now, this is the second and third well, and we're confirming that reserve target of between 650,000 and 700,000 barrels of oil equivalent. That's going to place these in that 50%-60% rate of return. It's really time for us to go to work there now. We've got three wells that are spread across the acreage that really confirms the viability of Wolfcamp B. 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 million. I actually think as we get in there with repeatable wells we can drive those costs down. As it sits right now with the $6 million well cost, that Clear Fork Shale is going to be somewhere between 30%-40% rate of return and probably 450,000-500,000 BOEs on an equivalent basis. While 30%-40% rate of return is still a good well, it doesn't compare when you look at the +70% to almost 100% rate of return, including the effect of minerals we get in Midland County. Don't expect us to get out there and just start drilling one well right after another. We've probably got, depending on spacing, maybe over 50 locations in the Clear Fork Shale.
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 two-well pad and see if we can get some cost efficiencies on a two-well pad and improve the economics there.
Great. I appreciate that. 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 nine rigs by 2016?
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. That water usage plan is sort of a holistic approach to access, accumulation, and disposal of water. 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. I think we're going to need all sources of stimulation water going forward, whether it's existing fresh water, brackish Santa Rosa water, or recycled water in order to match our rig needs. It's an issue that we're paying real close attention to and trying to make sure it's consistent with our development strategy.
Great. Appreciate that. 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 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-million-pound job up to 9-million-pound 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. Between sand and stimulation water, Dave, those are the two things that I think about.
Okay, great. I really appreciate the clarification. It's great work, guys.
Thank you, Dave.
Thank you. Our next question comes from Gordon Douthat of Wells Fargo. You may begin.
Thanks. Good morning, everybody. Just to dovetail off of that last question, recognizing it's a bit earlier in the Permian delineation, there's been a lot of talk recently about evolution of completion designs. 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 slick water fracs. Well, we did our first horizontal well over two years ago down in Upton County as one of the first operators to start drilling horizontal wells in areas that have predominantly drilled vertically. That first horizontal well was a slick water job. That's really, we've got over 80 of them completed, and I think 79 of them have had a slick water frac applied to it. We've continued to tweak sand per foot, water per foot.
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. That's that 22 stage going up to 33 stage, and we're doing it on a sister well. It's a pad well, one well, we'll do it with 22 stages, then just immediately over, we'll do the next well with 33 stages. We think that'll give us the best way to measure our improvement. It's about 3 million more pounds of sand. It's probably going to cost us about 1 million barrels, but if we can pick up a little more, $1 million, if we can pick up about 10,000 more barrels on an EUR it'll probably pay for it. Just look for us to provide more color as we go forward.
Okay. That's helpful. A question, Travis, you mentioned in your comments, prepared remarks that the rig allocation this year, as you add rigs next year, I'm just wondering how you look to allocate those rigs across the various areas of your position.
Yeah. We talked during our operations update 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. There's one and a half 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 93% 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. One of our competitors talked about a nice Cline result down in Upton County as well, which we haven't tested yet, but obviously, we'll pay close attention to there.
2, 3 Midland County, 2, 3 in the northern blocks, 1.5 in our newly acquired acreage, one or so down south. We'll get you into that seven and a half, eight rig cadence.
Okay. 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, was hoping you could talk about the opportunity set for Viper. You guys are really a first mover here with throwing the mineral rights in an MLP. I was just hoping you could talk about that, and then also, curious if there's, beyond just being a 92% owner of Viper, if there's any other added benefits that might not be obvious for Fang shareholders having that MLP in place. Thanks.
Yeah. Thanks, Mike. Really on the Viper side, the counsels 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 first 30 days. I think just look forward to us providing more color on Viper, in our upcoming calls. On this 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 webpage, and you can see all of those details.
Okay. Fair enough. Then, with Viper, is there the desire to go outside of the Permian and look for deals? Does that ultimately mean that Fang is obviously very Midland focused? You talk about ramping to nine 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's not constrained to the Midland Basin. Obviously, Diamondback is laser focused on execution results in the Midland Basin. The Viper level, we're looking for accretive deals in all the other basins. The three criteria we're looking for are basins that are actively being developed, oil-weighted basins, and the operator that's developing the minerals is a competent operator. Those are the three 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.
Morning, guys. Just curious, as far as, you talked a lot about just different infrastructure and bottlenecks. Just curious on the frack side as you're seeing that one, obviously, you keep ramping the rig count, and the plan is to ramp it further later this year and then next. What are you seeing as far as frack and as far as the contracts that you may have now or what you may have to look at as you go forward?
Yeah, 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 two 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. 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 can set a crew right there on the location and get two or three wells at one time. I'm still trying to do everything I can to hold the line on cost and offset any increases in costs with improved efficiencies. I do think that the tension is getting pretty tight now.
We've got two dedicated crews, as I mentioned, and we're looking at maybe bringing a third dedicated crew on later this year, early in the first quarter. One of the things that the stimulation companies have communicated to us is that they really like working for Diamondback Energy because even though right now we're just running five rigs, it's really equivalent to working for another company that's running eight or nine or 10 rigs because of how fast we get these wells drilled. It really 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. Maybe just on the other side of it, as you get the oil out, I know that you're always 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. 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 we'll hear shortly in the second half of this year that we ultimately believe 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. Just as a reminder, we've got 8,000 barrels a day gross that we've already committed and are moving right now on the Magellan Longhorn Pipeline, and we receive LLS pricing for that.
Any incremental barrels above 8,000 barrels a day have been subjected to that Mid-Cush differential. At least we've got a little insurance for our stockholders on 8,000 barrels a day. We're looking to 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 Connolly 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 third and fourth quarter that might help us model production?
Yeah. I was just talking with Jason there. I think we've got 40 wells that we've scheduled between now and the end of the year. With two full dedicated crews right now, it ought to be in that 20-ish wells per quarter. Again, we've got to have a little flexibility in that. In order to get our annual guidance of wells completed, we need to be in that 20 wells per quarter. That's the way 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. The majority of your wells going forward should be on at least two well pads. Can you talk about any potential to accelerate or to make those three or even more wells per pad? 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-quarters of our rig fleet available that walk from well to well. For example, that three-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 eight hours. Typically, it takes us two and a half days to move a rig, and so on a three-well pad, we moved them in eight hours. About half to three-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.
I can't have all of my rig fleet that are set up with feet because I need those fast-moving rigs. I'll look to Mike here real quick, but out of the six 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 four with the walking feet, and you'll have two that are H&P rigs that are quick movers. Spud rig release to spud times, you're looking at 2.5 to 2.8 days for the H&P rigs and a full pad with the walking feet to move from pad to pad's about three and a half days for one of the big 1,500 horse rigs with the feet. Then, as Travis mentioned, between wells, it's about eight 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 one to the next.
Thank you, Mike.
Yes, sir.
Perfect. 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, should we think about that as generally shifting towards the lower end of y'all's nine , six to seven, four completed well cost range, or should we think of it as actually shifting that range?
Well, I wish I could tell you that it's shifting the range lower. What I think it may end up doing is offsetting some of the cost increases that we're seeing. At this point, I don't want to signal that we're going to be lowering our range on the per well completions.
That's perfect. Thank you so much.
Thank you. Our next question is from Joseph Reagor of ROTH Capital Partners. You may begin.
Good morning, guys. Most of my questions have been answered, 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 three more rigs over the next 18 months?
Well, Joe, I talked a few minutes ago about our water usage plan for each area, a little bit more detail on that when it comes to access and accumulation. That means it's the number of freshwater or brackish water wells that we drill in advance of the drilling rig arriving, it also means we've got to size appropriately our storage frack pits for these types of water. That's what we're doing. On the newly acquired acreage, we're rapidly coming up with the water usage plans that gets all the way to how prolific the brackish water wells are, how prolific the freshwater wells are, then what size frack ponds we need to accommodate our rig schedule.
I think I had a previous question about increasing from two to three well pads, ideally, we'd like to stay with three well pads, 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, it takes a little longer to accumulate that amount of stimulation fluid.
Okay. Do you guys have an idea of what kind of relative cost and inflation impact that the water supply situation has had on you guys over, say, the last 12 months?
Yeah. 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 hundred thousand dollars a piece as opposed to a freshwater well, which is $10,000-$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.
Ladies and gentlemen, this concludes today's conference. Thanks for your participation and have a wonderful day.