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 session and instructions will be given at that time. I would now like to turn the conference over to your host, Adam Lawless, Investor Relations. You may begin.
Thank you, Mercy. Good morning, and welcome to Diamondback Energy's 2nd quarter conference call. Representing Diamondback today are Travis Stice, CEO Tracy Dick, CFO and Russell Panamuel, Vice President of Reservoir Engineering. 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. 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, and thank you all for listening to Diamondback Energy's Q2 2013 conference call. Since our last call, Diamondback Energy has continued to make significant progress across all fronts. We've ramped production to 100 barrels a day, that's up 30% or over 1800 barrels a day from the Q1. We've generated execution results we believe are among the best in the basin and we realized operating expense reductions with LOE for the quarter at $10.15 a barrel.
And lastly, we've expanded our footprint by over 11,000 net acres. Our results along with other operators continue to highlight how prospective Diamondback's acreage is within this play. We're seeing impressive well tests from other operators in Northern Midland Basin, which looks to be expanding the play towards where we now have over 29,000 net acres including our recently added position. Our private operator reported results from a Lower Spraberry horizontal well located within a mile and a half of our Midland County acreage, which tested at over 6 30 barrels a day from a short lateral. As a result, we've increased our horizontal inventory by 126 locations in the Spraberry.
The Pioneer operated Hutt Wolfcamp A, the first reported Wolfcamp A bench test in Midland County has also shown potential along with their Mabee Wolfcamp B well located in Martin County. Both of these Wolfcamp wells posted impressive production rates. These are key wells in expanding the vertical section and the aerial extent of the Midland Basin shells. As I've said before, we intend to be fast followers as the industry continues to deliver promising results in other horizons. Referring to our earnings release issued yesterday, you can see the details associated with each of our horizontal wells.
In Midland County, we previously reported a peak IP rate on the Spanish Trail 40 three-one at 11 36 barrels a day and we now have a 30 day average rate of 9 16 barrels a day. Both of those are equivalent rates. In Upton County, the JCA Unit 1H had a peak IP of 1085 barrels a day and a 30 day average rate of 6.32 from a 7,500 foot lateral along with 2 Janie short lateral wells, the 2H and the 4H with peak IPs at 9 30 barrels a day and 8 80 barrels a day, respectively. When we evaluate our performance using this early time data for all of our horizontal wells, we remain at or above our average type curve projections and at or below our cost projections, which I'll touch on later. As a reminder, we've guided towards 550,000 to 650,000 barrels reserves for 7,500 foot lateral, again on an equivalent basis.
We're currently running 3 horizontal rigs, 1 in Upton and 2 in Midland County with the 4th rig scheduled to arrive during the 4th quarter. Our 23 horizontal wells in various stages of development and over 100,000 feet of lateral footage drilled since we began our horizontal program, I'm confident that Diamondback is leading the way in delivering strong horizontal well results and value to our stockholders. Turning to our quarterly results. We're pleased with our production for the Q2 of 2013, which averaged 6,600 BOEs a day. This represents an increase of 38% or up 1800 barrels a day when compared to the Q1 of this year.
Also, since the percentage of oil from these horizontal wells is high, our increase in oil only production is 49% for the quarter. Our operations team continues to improve performance to a level we believe is among the best in the Midland Basin. We had a 7,500 foot lateral in Upton County reach TD in 14 days along with our very first 10,000 foot lateral, which reached TD in 19 days to a measured depth of 19,620 feet. This well has been completed and we're currently drilling out frac plugs. We drilled and completed the Janney 4H in Upton County at a total cost of $4,800,000 our first sub $5,000,000 short lateral.
Our 2nd quarter well cost for short laterals were $5,300,000 which represents a 12% improvement over the Q1 this year and our most recent 7,500 foot lateral came in at $7,200,000 This steady sequential improvement is very encouraging as we look forward and establish plans for 2014. With these impressive execution results, we are seeing well costs migrate to the low end of our guidance of $7,500,000 to $8,500,000 for 7,500 foot laterals with further upside possible as we continue to optimize our completions and begin pad drilling in Midland County. We feel pad drilling should generate additional well cost reductions. The first two well pad test will begin next week with the spud of a 5,000 foot Wolfcamp B well followed by our second set of pad wells in late Q3, early Q4 of this year. While we'll see a slight increase in our POP time or placed on production time for these pad wells, we anticipate as much as 400 dollars to 500,000 savings per well utilizing this zipper frac methodology.
With regard to our vertical program, we've seen improvements again this quarter with spud TD times decreasing by 11% to average of 8 days. 3 of these wells reached TD in less than 7 days. Our vertical well costs are now averaging $1,900,000 We've also began testing the horizontal potential of our Andrews County leasehold with horizontal wells drilled now both in the Wolfcamp B and in the Clear Fork Shale intervals. We just completed the 4,000 foot lateral Wolfcamp B well with 19 stages using slickwater and flowback operations are underway with the well just beginning to cut oil. We will begin the 7,500 foot Clear Fork frac next week.
We're pleased with our drilling results since we reached TD in 19 days for the Wolfcamp B well and 17 days for the Clear Fork well, both of which appear to be among the fastest to TD we've seen relative to nearby horizontal drilling activity. As you can see, we're making considerable progress on the cost side. Our 2nd quarter total LOE per BOE decreased 20 percent to $10.15 a barrel. This is the 2nd quarter in a row we've reduced LOE by 20% and represents a reduction of almost 45% from our high during the Q3 of 2012. We continue to lower unit LOE both by driving cost out of the equation and by increasing volumes.
Our direct LOE is now below $8 a barrel. We've placed the majority of our water production on pipe. We've released rental gas process and equipment and we've electrified the majority of our leasehold. With the first half of twenty thirteen behind us at an average of $11.38 a barrel, we're well on our way of our goal to reduce our total LOE to the lower end of the range of $11 to $13 for the full year of 2013. Finally, we're pleased to announce that we've entered into definitive agreements to acquire approximately 11,150 net acres with an average NRI of 78 percent from private parties for $165,000,000 including approximately 800 barrels a day of production and 200 barrels a day of behind pipe production or PDP from 34 vertical wells.
With 25,000,000 to 30,000,000 barrels of net resource potential associated only with the Wolfcamp B bench, our acquisition costs are around $3 to $4 per barrel. These assets, one located in Martin County and the other straddling the Martin Dawson County line, provide us with strategic position to export Northern Midland Basin Shales across multiple benches. In addition to the Wolfcamp B, we believe the acreage is also perspective in the Middle and Lower Spraberry, the Wolfcamp A and the Cline, also sometimes referred to as the Wolfcamp D. As these other intervals become derisked, we believe we can add potentially over 300 horizontal locations to our drillable inventory. Approximately 85 locations are Wolfcamp B, which expands that inventory by 26% to over 400 locations and increase our total inventory across all zones to approximately 1200 gross horizontal locations.
I'll be able to provide color on how these acquisitions will impact 2014 during our next call in November. But simply stated, it's more of a good thing. With those comments complete, allow me to turn the call over to Tracy.
Thank you, Travis. Our net income for the quarter was $14,500,000 or $0.36 per diluted share. Net income for the period included an unrealized gain on commodity derivatives of $3,900,000 Excluding the unrealized gain and the related income tax effect, adjusted net income was $11,900,000 or $0.30 per diluted share. Revenues for the quarter totaled 45 $400,000 a 57% increase as compared to Q1 of 2013. Our sequential quarter over quarter $16,500,000 increase is supported by increased production volumes from our horizontal wells as well as higher price realization.
The production volumes contributed $12,900,000 of this increase, while the remaining $3,600,000 was the net dollar effect of the increase in our price realization. Our average prices before the effect of hedges was $75.70 per BOE, an improvement of approximately 13% when compared to $67.09 per BOE for the prior quarter. Our average realized price, including the effect of hedges, was $74.27 per BOE compared to $63.51 per BOE for the prior quarter. EBITDA for the quarter was $35,100,000 compared to $20,300,000 in the prior quarter, an increase of 73%. Turning to our costs.
Our lease operating expenses were $10.15 per BOE as compared to $12.16 per BOE in the Q1 of 2013, a 20% decrease. Our general and administrative costs came in at $4.37 per BOE and in line with our guidance of between $3 $5 per BOE. Our production tax and DD and A are both in line with guidance. At quarter's end, we had no debt and undrawn borrowing base of $180,000,000 Our liquidity position at quarter's end in the form of cash on hand and borrowing capacity was approximately $260,000,000 Our next redetermination is planned for next month. During the Q2, we layered on an additional oil derivative position of 1,000 barrels per day at LOS pricing of $100.22 for 12 months beginning July 2013.
We continue to look at layering on additional hedges as our production grows. In the Q2 of 2013, we generated $33,000,000 of operating cash flow. Our capital expenditures were approximately $64,600,000 which included $55,600,000 for drilling and completion, dollars 5,000,000 for leasehold acquisitions and the remainder for infrastructure and facilities. Our capital spend is on track to be in line with our annual capital guidance. I'll now turn the call back over to Travis for his closing remarks.
Thank you, Tracy. To summarize, we feel we've generated very positive results again for the quarter. We're very excited about these acquisitions because it gives us the opportunity to demonstrate what we do best, execute. We've continued our production ramp. Execution is at or near the top in our drilling results.
Expenses are down. Development costs on both horizontal and vertical wells continue to trend down and we've yet to draw on our borrowing base. On behalf of the Board and employees of Diamondback Energy, I'd like to thank you for your participation today. This concludes our prepared comments. Operator, please open the call to questions.
Our first question is from Brian Othman from SunTrust. Your line is open.
Hi, good morning. Good morning, Ryan.
I'll leave the acquisition questions for someone else, but I want to talk about your operations here. In Upton County, this Janney 4H was completed with only 10 frac stages, but it looks like it's in the same ballpark as the Janney 2H, which was completed with 19 frac stages. Can you talk about what you're doing there and the potential productivity implications for the whole play?
Yes. I think just to answer the productivity questions, we're still early in the analysis of that particular frac methodology. But certainly what we've seen from early time data, the IP in the 1st 30 days, we've not made any material change to the production profile. Now specific to your question, what we did there was we attempted to pump the same amount of sand and water as we do in a more typical 19 stage frac job except we actually spread the interstage distance out a little bit. So I think it's important to note that we're not going kind of counter to industry by spreading out the actual perf clusters.
But what we're really doing is just spreading out how much we can place in each stage. So we still got about 85% or 90% of the amount of sands placed and water placed in a 10 stage job as we did in a 19 stage job. And the implications, certainly if we can if we validate that we can that we've not done anything to the EURs because we're pretty confident now on an IP perspective, The implications are more on the cost side. We save probably $300,000 to $400,000 just on the frac ticket alone by spreading these stages out. And then we've got the other ancillary costs with wireline and frac plugs, etcetera, that also add some additional cost savings.
So the implications are more on the cost side than they are on the reservoir performance side, Ryan.
Okay, great. And vertical well costs also coming down about $1,900,000 last quarter versus your $2,000,000 to $2,200,000 guidance. What's driving that reduction? Is it drilling days? Is it better availability of rigs or crews?
Yes, it's really a combination. As I pointed out, some of these wells, these guys got them drilled in 6 point something days, less than 7 days. So, there's certainly a drilling efficiency piece to that component as well. And then we're also continuing to take advantage of surplus of services in some areas out in the Permian and taking advantage of lower cost. And then lastly, I want to give credit to the guys for both on the completion and the drilling side.
So just making sure they scrutinize every cost element and make sure that we're competitive on every cost element of the AFE in order to get those costs down to where they're at today.
Okay. And then drilling days, it does look like are coming down significantly. Does that change your plan for how many horizontal and vertical wells you think you can drill this year?
Yes, it does, Ryan. We're probably we probably can get maybe 4 or 5 more horizontal wells drilled this year if we were able to replicate this cadence. But the other side of that is on the cost side. We're saving money on all these wells also, which is kind of why we've left our CapEx guidance unchanged. So, certainly, with continued in performance, our cycle time is going to continue to be impressive.
I think we've got 18 wells between now and the end of the year on the board right now that we've got to drill and complete.
Okay. And then Andrews County, it looks like it's early days with these two wells. Any color on the early production from the Wolfcamp B test or how that Clear Fork drilled?
Yes. The Clear Fork drilled really good. I mean, they got a 7,500 foot lateral drilled up there in 17 days. So the drilling went really and then for our first well up there, it went extremely well. So really pleased with that.
And as I mentioned, we're going to start fracking that well next week. And then the Wolfcamp B well, Ryan Cross, I mean, it just we just started flowing it back. It's just started cutting oil a couple of days ago. So really, really early times.
Got it. That's it for me. Thank you.
Thank you, Ryan.
Thank you. Our next question is from Kurt Friedman from Simmons and Company. Your line is open.
Good morning, guys.
Hi, Kurt. Thinking towards the A and D market here, obviously great to have this acquisition behind you. I'm curious how having this acquisition behind you may change your perspective for continuing to acquire leasehold in ensuing quarters, specifically has your appetite changed perhaps being less conservative to more conservative now that you have this big deal behind you?
That's a good question, Kurt. I'll tell you we're going to continue to be opportunistic. I mean we're we've got the financial firepower to do deals. And if we think these deals are accretive to what we currently have in our inventory and we can take advantage of our 1st mover status in this kind of horizontal development, we're going to continue to push the envelope on acquiring additional assets. But again, I want to stress that we're going to be opportunistic and we're going to always balance those opportunities against our existing inventory and make sure we're being accretive every time we do one of these deals.
Okay, great. And
then kind of sticking with the acquisition for now, given that there was some EBITDA associated with the purchase, could we potentially see you guys issue debt from the acquisition or any color you can provide there?
Sure. I think, Kurt, what we're doing is we're evaluating all of our options. But as it sits today, we expect that we'd probably do a combination of taking advantage of the cash on hand, which Tracy talked about, borrowings under our credit facility, which as I mentioned, they're currently undrawn or proceeds from some kind of offering of securities. So likely a combination of those three things.
Okay, great. And then last one for me kind of moving on to the operations. For this 4,302 H well in Midland County, it looks like on a lateral length adjusted basis, it may have come on a little bit weaker relative to some of your other strong wells out there. And so I'm curious if there's anything specific to this well that's worth highlighting that may have been a cause for slight underperformance relatively.
Sure. Yes, sure. Good question, Kurt. Yes, what we attempted to do on that well is we had its sister well, the 4031, which is immediately adjacent to it and we thought that'd be a good opportunity early on in the program to do some side by side testing of different frac methodologies. We've always been a proponent of slickwater.
In fact, all the wells we've done besides this one have been slickwater fracked. What we wanted to do is experiment with a hybrid frac technique where you start off with slickwater and you follow in with the linear and cross link system. And that's what we did on that 4032H. And the job went exactly as designed. It's just from an IP perspective, it looks like it's down quite a bit from its offset well.
And we're struggling to try to figure out exactly is that a function of the gel system that we put in there? Is there something going on downhole? Or could there in the reservoir? Or could there potentially be something mechanical? But I'll tell you, we're uncertain enough about it right now that you won't see us doing any more hybrid jobs for the in the near term.
Great. Thanks guys.
You bet. Thank you, Kurt.
Our next question is from Mike Leer from Credit Suisse. Your line is open.
I guess just a little bit more on the inventory front. I guess with the Spraberry locations and other Stack Pay, I guess, can you talk about when you're thinking about drilling a lower Spraberry well and I guess derisking some of the other zones across your asset base?
Yes. Mark, I think the most likely next test would be a Spraberry well in the second half of this year. And we're in conversations right now with some of our partners to maybe potentially get a spray barrier well on the board before the end of the year. And then the other zones, it's hard to look at a Wolfcamp A well that's plus 1500 barrels a day right in your backyard and not be encouraged to go and try that. But we're looking at our mapping and picking some locations right now, but that may be late this year or the next year type of test.
Okay.
And then on the deal, can you talk about the acreage split between Dawson and Martin? And then anything on the any detail on the reserve add?
Yes. The split of the 2 acreage blocks and they're 2 nice contiguous blocks and they're perfectly both these blocks are perfectly laid out for repeatable 7,500 foot type of horizontal wells. So they're really chunky in these two blocks. And the Dawson County block is about 6,000 acres and it's right on the county. In fact, it straddles the Dawson County, Martin County line.
And then the other block is about 5,000 acres and it's just a little south of that. It's about it's immediately east of our existing leasehold in Northeast Andrews County. And then from a reserve add perspective, there were 34 vertical wells that are producing those 800 odd barrels a day. And Mark, we'll have to get back with you on the reserve component of those wells. I don't have that in front of me.
Okay. And then I guess just lastly on the ops front. I guess just from the data you provide, the longer lateral wells don't necessarily show the same level of productivity from a lateral foot standpoint. And just wondering if there's any explanation maybe from a facilities standpoint. I mean, do you expect these longer laterals to be demonstrate flatter curves over time?
Just kind of wanted to get a sense on the reason for that.
Sure. I wish I could give you a real definitive answer. I mean, we've explained the 43,200,000 which may have something to do with the way we completed it and it was a longer lateral and the Spanish Trail 7.1, while we're still pleased with it, we also kind of experimented with a slow back technique where we flowed the well back lot less aggressively and so that impacted the 30 day rate. We don't really think it had anything to do with the will have anything to do with the reserves. But certainly that's something we're looking at Mark.
I mean as we continue to drive costs down, we still think that it's a pretty much a one to one relationship between 7,500 foot and even the first 10,000 foot well, but it's something we'll pay close attention to.
Got you. Thanks guys.
Next question is from Eli Contour from Iberia Capital Partners. Your line is
open. Hey, good morning guys. Hey, good morning Eli.
Just a quick question on LOE. It looks like you posted an impressive quarter over quarter decline there. But relative to peers, it looks like there might be an opportunity to continue to lever your operating cost structure as production ramps. How should we think about that number going forward?
Well, LOE is one of those numbers that I think we've talked before, Eli, that we're never really satisfied with the number. We think there's always opportunity to drive cost out of the equation. I outlined in my prepared comments kind of those major levers that we cranked on to get to the status we're at right now. We've got one more probably major lever that we're going to crank on, which is recycling this flowback water in our frac jobs and that will take some water handling out of the equation and that will be another potential stair step change in LOE. And then the other thing is we're still with the 3rd rig.
We're working right now and the 4th rig that will arrive in the 4th quarter. We'll work on the denominator of that unit cost basis as well by increasing volumes. So, we've been pretty conservative in our with the numbers we posted today, dollars 11.30 something for the first half of the year, we're going to be at the low end of our full year guidance of between $11 $13 a barrel and I certainly expect we'll continue to make improvements on LOE going forward.
That's helpful. Follow-up question for me just on drilling activity as you look into 2014 beyond. Should we anticipate a move towards 100% horizontal drilling next year? Or is that something that might happen later on down the road?
Well, when you look at a company our size, we're almost there right now. I mean, we've got 3 horizontal rigs and only 1 vertical rig. And so the vertical rig is we're essentially just doing that to try to maintain lease obligations where we can't meet those obligations horizontally. So we'll continue to push to drill as few vertical wells as we need to and focus mostly on the horizontal. But we're certainly all in on horizontal development.
Okay. Thanks guys.
Next question is from Richard Tullis from Capital One. Your line is open.
Good morning. Travis, could you give us the production current production rate or at least the 2Q exit rate?
Yes. 2Q exit rate, we're running a little north of 7,000 barrels a day. Okay.
Looking at the newly acquired acreage in Northern Martin, Southern Dawson, Can you talk about any offset wells from other operators that give you encouragement on the area?
Well, let me back up just for a minute. When we talk about these resource plays, one of the reasons that they're called a resource play is because the way that these assets are deposited, they have large regional extent to the plays. And probably now specifically to your question, Richard, we've seen the Pioneer maybe well, which I think is about 15 miles from our Martin County acreage, 1500, 1600 barrels a day out of the Wolfcamp B. We've mapped that Wolfcamp B from our Midland County acreage up through that well, up into our Andrews County where we've got the well flowing back right now into this newly acquired acreage and we like what we see. And using those same mapping techniques, we like what we see in the 2 Spraberry benches I talked about as well as the A and as well as decline.
So, probably the furthest north most well other than the well we're flowing back right now is that Pioneer well. Okay. And there's been some Wolfcamp A activity in and around our area up there by some other publicly traded operators up there as well too.
Okay. And given the acquisition, what sort of CapEx range could we expect next year including drilling on the new area?
Yes. That's a fair question Richard and I know there's a lot of interest to what our 2014 CapEx is going to be. But you've got to wait for me until about November when I roll out my full plan and we'll be able to give you a real wholesome view of what our 2014 looks like at that time.
Okay. And then just lastly for me, I guess this acquisition gives us a pretty good indicator of what the Martin County acreage is going for currently. What is the current acreage cost do you see in Midland County?
I mean, you look at the same data that we do Richard. We've got a couple of transactions that occurred with RSP and Resolute and then the Pioneer deal down in their JV area. So those are the same data points that we look at.
Okay. All right. Thanks a bunch.
You bet, Richard.
Our next
Our next question is from
Jason Wangler from Wonderland Securities. Your line is open.
Good morning. Just curious on the new stuff. What do you see at least I know you don't really have a good feel for next year yet, but for this year will there be some drilling? Is there anything you need to hold leases or will you even maybe look to sort of horizontal as you get that close and kind of get your hands on it?
Yes. We might look at horizontal getting a horizontal well or to drill there early or late this year, early next year. Any vertical wells we might drill might be to access a little some science. But at this point right now, we're still putting our full development plan together as respect to timing of when we'll get up there and drill. But the lease obligations aren't so on Seronos that we're going to have to go up there and drill a lot of vertical wells to keep the blocks together.
And just in general, where do you think on a rough estimate are you as far as held by production for, I mean, I guess, your, if you call it legacy acreage and then obviously this new stuff to maybe where those numbers are just for an idea of the vertical programs going forward?
Yes. If you look at our legacy acreage, we're around 40% held by production. And then you had a what was your second part of that question?
Just the and then the new acreage that you're acquiring, do you have a rough estimate there?
It's about 30% HBP. That's helpful. Thank you.
Our next question is from Heapsik Mahanty from Canaccord. Your line is open.
Hey, good morning, Travis and team. Just my first question is a broader question on looking at your acreage, wondering if you can see your confidence level about Wolfcamp prospectivity in the counties other than Midland and Upton, that is Crockett, Hector and then the western portion of the Andrews County please?
Yes. Crockett County, we're watching what industry is doing down there in the not only the Wolfcamp B, but some other benches are being tested down there as well too. We're going to be a fast follower down there. Those leases are still in their primary term. So don't expect us anytime soon to drill a horizontal well down there unless industry data materially changes.
We might go down there and do a core hole. Ector County, the eastern side of Ector County, our acreage block has some potential in decline and the Wolfcamp B starts to thin over there. So, we've got to kind of balance at what point we test a thinner Wolfcamp B to test its prospectivity. And then the western side of Crockett County I'm sorry, the western side of Andrews County, that block that's close to the shelf's edge. The Wolfcamp is absent on the right up there against the shelf's edge and it tends to less than 100 feet on the eastern side.
But the Clear Fork Shale looks extremely good, which is why we drilled that 7,500 foot horizontal there. So we think while what we may not have in Wolfcamp B prospectivity, we more than made up for it in the Clear Fork and we'll test that here in the next couple of weeks when we get that frac done.
Sure. And then the one on your recent M and A. I believe your production included vertical wells. So what gives you confidence about those 69 horizontal locations you've outlined as well as the other prospective zones A and Klein and all those guys?
Yes. And certainly, there's a grade of confidence across all the other zones. But the data that we've looked at that has us the most excited of the Wolfcamp B and we were excited about that Wolfcamp B prospectivity, both from the thickness that's been deposited up there, but also the resistivity and the porosity. And then when we saw the Pioneer test on the Maybe Ranch post that really nice number that sort of sold it for us in the Wolfcamp B. So kind of confirmed what we were looking at in the math sense.
So that Wolfcamp B we're really confident in. And then the Wolfcamp A again even though it's probably 50 miles away down in Midland County that other really nice Wolfcamp A well, again, in a resource basin like these shales are out here in the Midland Basin, they run aerially for a very long way and we like what we see in the Wolfcamp A and the Spraberry like I talked about. So our confidence obviously has a band of uncertainty around it. We probably are extremely confident about the Wolfcamp B and then we're follows with the Spraberry and after that and then ultimately the declines kind of our order of confidence.
Okay. Well, one last if I may on the OpEx. You've kind of obviously done a great job sequentially bringing it down, but you still maintain your guidance for the 2013 as before. Is there a reason why you're not kind of thinking of bringing it down or it's
Yes. I think the words I used, Ipsit, in my prepared remarks was that we're going to be at the low end of our range for a full year guidance. For our full year performance, we'll be at the low end of our range, which is $11 a barrel. And we average in the first half of the year, dollars 11 I think $11.38 a barrel and we've got in the second half of the year to go. So we just want to make sure that before we start moving our guidance down down that we're going to be able to achieve that guidance.
So right now just be confident that we're communicating at the low end of that range.
We will be. Thank you.
Next question is from John Freeman from Raymond James. Your line is open.
Good morning. Very impressive cost reductions on the wells. Could you give the what that cost came in on the 10,000 foot lateral? I think initially you were targeting about $9,000,000
Yes. We're still like I said, we're drilling out plugs, so that well is not complete yet. But we'll be in that it will be in that $9,000,000 to $10,000,000 range. But I hate talking about a well that's not completed yet. So we've got about a half the plugs or 2 thirds of the plugs left to drill out on it.
So there's a lot of as any horizontal well, there's always operations risk associated with drilling plugs in.
Okay. I understand. And then, obviously, you've talked some about some of the things you did a little differently on the frac design on some of these wells like the 40 3.2. But when we're just thinking about your standard kind of completion technique, is it still appropriate to think about it as £300,000 per stage and 250 feet between stages?
That's correct. And one of the things that we may we're always tweaking it. As engineers, we always try to tweak things and make them better. And one of the things we're looking at tweaking right now is the amount of sand we're trying to place in these wells where we're going to £300,000 right now, which typically split about 30seventy between 100 mesh and 40seventy. We're looking at maybe tweaking the amount of 100 mesh that we initiate these fracs with.
But again, those are just they're more than substantive changes. They're more just tweaks existing model.
Great. And then just the last question for me on the Longhorn pipeline. I think you all were targeting by the end of the Q3 to sort of be at your full sort of capacity getting up to like the 8,000 gross number, is that still kind of on track?
Yes. And again, excuse me, we're not in control of our destiny there. I mean, that's a function of the pipeline and how quickly they can get up to their full capacity. They've repeatedly talked about Longhorn Magellan has repeatedly talked about late Q3, early Q4 being at their full capacity. But where I sit as an operator contributing volumes to that pipeline, it's been a little slow in the uptake on getting up to that full capacity.
So, we've been prorated May, June July, it's around 1500 to 2000 barrels a day. So, it won't be until that pipeline is at full capacity of 225,000 barrels a day that will be at that 8,000 barrel a day gross number that you referenced.
Great. I appreciate it. Thanks a lot.
You bet, John. Thank you.
Our next question is from Mark McDowell from Peregrine Investments. Your line is open.
Hey, guys. I had most of my questions have been answered, but I do have a few more regarding inventory. You mentioned 120, I believe, gross inventory for Spraberry. Is that do you have an expectation on EUR for that? I know it's still early stage.
Yes. I think the real numbers, I think we quoted 126 or something. But just from an EUR perspective for a long lateral, we'll be in that maybe 5000 to 600000 BOE range. I mean, again, that's a pretty we've not drilled one yet. So just based on what we're seeing out of that one data point for a 7,500 foot lateral that's kind of what we think.
Now again as I mentioned though the development costs since it's shallow, we're not actually eliminating casing string are going to be quite a bit less. So from a cost to develop, which is how we look at some of our investments, it's going to be competitive with the Wolfcamp B.
Got you. And then regarding operating costs, in your presentation, you gave some well economics for horizontal wells. Does 10 dollars 0.15 LOE when you're running is that below or in line with the operating costs you guys were using to calculate those well economics? I mean how does that compare?
That will be a little bit below. Our actual performance will be a little bit below what we're using in the economics. So that will actually improve the economics. But again, what moves the needle on these wells while LOE is critically important to how we run our business, what really moves these wells is the commodity price and the reserves and the rate. LOE and G and A fall they're further down the list of importance.
Got you. And I guess last question for me. Correct me if I'm wrong here, but I thought you mentioned 300 gross locations for the acquisition. Can you you mentioned 85 Wolfcamp B. Did you have an estimate for what Wolfcamp A and Spraberry would be out of that 300?
Yes. We didn't provide that during the call, but it's and actually I don't have that in front of me. Mark, I'm sorry. So we'll just have to get back with you on that.
Okay. Thanks guys. That's
it for me. Yes. I guess Mark, Russell was just talking to me there. I guess it's going to be very similar to what we have in our existing inventory. I mean, it's the same rock.
So kind of on a percentage basis, if you want to just get a rough estimate, you could do the same thing and that's in our pitch book as well.
Got
it. And just you were mentioning the cost and since you referenced that slide in our pitch book, the fact that we've been able to knock these costs down sequentially, I've got in our pitch book for every $100,000 we knock off our well cost. We improve our cost to develop by $0.25 a barrel. So that's obviously accretive not only to rate of return, but cost to develop as we continue to post these nice lower well costs.
Thanks.
Our next question is from Ryan O'Thun from SunTrust. Your line is open.
Hi, guys. Thanks for taking follow-up here. Wanted to ask on this acquisition. There's some vertical well production on it. Was just curious how those wells are performing say to your typical type curve for your Wolfrey assets and what that tells you about the prospectivity of the acreage, the productivity of this acreage?
Yes. Yes. Relative to what we typically see from a vertical well, those wells in Martin County, which is where the majority of those vertical wells sit, they're going to be in that 130 to 140 MBO range, which actually are going to generate pretty nice economics at our development cost. So, as again, as I mentioned, we're not we didn't acquire this asset for vertical wells, but we do have a nice inventory of economic 20% to 30% rate of return type of investments up there as well.
Right. And then kind of a random question here on spacing. I see that some of the location counts are based on 100 and 60 acres spacing. Is there a chance for that to move down? I know some of the other folks in the basin are testing 60s, 80s, 100?
Yes. And we're obviously very interested in the results of those tests as well too. And so I hope those tests prove productive and down spacing is something that I can talk to you guys about in the upcoming quarters. But where we sit right now, we're I don't know if you want to call it conservative or not, but we're we've got 6 across the section for the Wolfcamp B and then in a general sense only 4 across the section for all these other horizons. So, I hope industry proves up to down spacing works because we're perfectly positioned to have a material uptick in our inventory if that works.
Great. That's it for me.
Thank you. We have no further questions. I'd now like to turn the call over to Travis Stice, CEO for closing remarks.
Thank you, Mercy. I know you guys judging by a lot of late night e mails and early morning e mails, I know it's a busy time for you. So I appreciate the interest that you guys have in Diamondback Energy and participating in today's call. And we really appreciate the call today. Thanks everybody.
Ladies and gentlemen, this does concludes today's conference. You may now disconnect. Everyone have a