Good day, ladies and gentlemen, and welcome to Diamondback Energy second quarter earnings call. At this time, all participants are in listen only mode. Later, we'll conduct a question and answer session, and instructions will be given at that time. I'd like to turn the conference over to your host, Adam Lawlis, Investor Relations. You may begin.
Thank you, Mercy. Good morning, and welcome to Diamondback Energy second quarter conference call. Representing Diamondback today are Travis Stice, CEO, Teresa Dick , CFO, and Russell Pantermuehl, Vice President 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 on 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 second quarter 2013 conference call. Since our last call, Diamondback Energy has continued to make significant progress across all fronts. We've ramped production to 6,600 barrels a day. That's up 30% or over 1,800 barrels a day from the first quarter. 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. 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.
A 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 630 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 shales. 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 43-1 at 1,136 barrels a day, and we now have a 30-day average rate of 916 barrels a day. Both of those are equivalent rates. In Upton County, the Jacee A Unit 1H had a peak IP of 1,085 barrels a day and a 30-day average rate of 632 from a 7,500-foot lateral, along with two Janey short lateral wells, the 2H and the 4H, with peak IPs at 930 barrels a day and 880 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 550,000-650,000 barrels reserves for a 7,500-foot lateral, again, on an equivalent basis.
We're currently running three horizontal rigs, one in Upton and two in Midland County, with a fourth rig scheduled to arrive during the fourth 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 second quarter of 2013, which averaged 6,600 BOEs a day. This represents an increase of 38% or up 1,800 barrels a day when compared to the first quarter 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 Janey 4H in Upton County at a total cost of $4.8 million, our first sub $5 million short lateral. Our second quarter well cost for short laterals were $5.3 million, which represents a 12% improvement over the first quarter this year, and our most recent 7,500-foot lateral came in at $7.2 million. This steady sequential improvement is very encouraging as we look forward and establish plans for 2014.
With these impressive execution results, we're seeing well costs migrate to the low end of our guidance of $7.5 million-$8.5 million 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 third quarter, early fourth quarter 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 $400,000-$500,000 savings per well utilizing this zipper frac methodology.
With regard to our vertical program, we've seen improvements again this quarter with spudded TD times decreasing by 11% to an average of eight days. Three of these wells reached TD in less than seven days. Our vertical well costs are now averaging $1.9 million. 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 slick water, and flow back 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 second quarter total LOE per BOE decreased 20% to $10.15 a barrel. This is the second quarter in a row we've reduced LOE by 20% and represents a reduction of almost 45% from our high during the third quarter 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 processing equipment, and we've electrified the majority of our leasehold.
With the first half of 2013 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-$13 for the full year of 2013. 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% from private parties for $165 million, 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 million-30 million barrels of net resource potential associated only with the Wolfcamp B bench, our acquisition costs are around $3-$4 per barrel.
These assets, one located in Martin County and the other straddling the Martin/Dawson County line, provide us with a strategic position to export Northern Midland Basin shales across multiple benches. In addition to the Wolfcamp B, we believe the acreage is also prospective 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 de-risked, 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 1,200 gross horizontal locations. I'll be able to provide color on how these acquisitions will impact 2014 during our next call in November. Simply stated, it's more of a good thing.
With those comments complete, allow me to turn the call over to Teresa.
Thank you, Travis. Our net income for the quarter was $14.5 million, or $0.36 per diluted share. Net income for the period included an unrealized gain on commodity derivatives of $3.9 million. Excluding the unrealized gain and the related income tax effect, adjusted net income was $11.9 million, or $0.30 per diluted share. Revenues for the quarter totaled $45.4 million, a 57% increase as compared to first quarter of 2013. Our sequential quarter-over-quarter $16.5 million increase is supported by increased production volumes from our horizontal wells, as well as higher price realization. The production volumes contributed $12.9 million of this increase, while the remaining $3.6 million was the net dollar effect of the increase in our price realizations. 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 $35.1 million, compared to $20.3 million 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 first quarter 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 and $5 per BOE. Our production tax and DD&A are both in line with guidance. At quarter's end, we had no debt, an undrawn borrowing base of $180 million. Our liquidity position at quarter's end in the form of cash on hand and borrowing capacity was approximately $260 million. Our next redetermination is planned for next month.
During the second quarter, we layered on an additional oil derivative position of 1,000 barrels per day at LLS 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 second quarter of 2013, we generated $33 million of operating cash flow. Our capital expenditures were approximately $64.6 million, which included $55.6 million for drilling and completion, $5 million 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, Teresa. 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.
Thank you. Ladies and gentlemen, if you have a question at this time, please press the star then the number one 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 Ryan Oatman from SunTrust. Your line is open.
Hi, good morning.
Good morning, Ryan.
I'll leave the acquisition questions for someone else. I want to talk about your operations here. In Upton County, this Janey 4H was completed with only 10 frack stages. It looks like it's in the same ballpark as the Janey 2H, which was completed with 19 frack 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 frack methodology. Certainly what we've seen from early time data, the IP in the first 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 frack job, except we actually spread the inner stage distance out a little bit. I think it's important to note that we're not going counter to industry by spreading out the actual perf clusters. What we're really doing is just spreading out how much we can place in each stage.
We still got about 85% or 90% of the amount of sand placed and water placed in a 10-stage job as we did in a 19-stage job. The implications, certainly if we validate that we've not done anything to the EURs, because we're pretty confident now in an IP perspective, the implications are more on the cost side. We saved probably $300,000-$400,000 just on the frack ticket alone by spreading these stages out. Then we've got the other ancillary costs with wireline and frack plugs, et cetera, that also add some additional cost savings. The implications are more on the cost side than they are on the reservoir performance side, Ryan.
Okay, great. Vertical well costs also coming down about $1.9 million last quarter versus your $2 million-$2.2 million guidance. What's driving that reduction? Is it drilling days? Is it better availability of rigs or crews?
Yeah, it's really a combination. As I pointed out, some of these wells, these guys got them drilled in six-point something days, in less than seven days. There's certainly a drilling efficiency piece to that component as well. We're also continuing to take advantage of surplus of services in some areas out in the Permian and taking advantage of lower costs. Lastly, I want to give credit to the guys for both on the completion and the drilling side to 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. 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?
Yeah, it does, Ryan. We probably can get maybe four or five more horizontal wells drilled this year if we're able to replicate this cadence. The other side of that is on the cost side. We're saving money on all these wells also, which is why we've left our CapEx guidance unchanged. Certainly with continued 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. In 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?
Yeah, the Clear Fork drilled really good. They got a 7,500-foot lateral drilled up there in 17 days. For our first well up there, it went extremely well. Really pleased with that. As I mentioned, we're going to start fracking that well next week. The Wolfcamp B well, Ryan we just started flowing it back. It's just started cutting oil a couple of days ago. Really early times.
Got it. That's it for me. Thank you.
Thank you, Ryan.
Thank you. Our next question is from Kerr Friedman from Simmons & Company. Your line is open.
Morning, guys.
Hey, Kerr.
Thinking towards the A&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, how your appetite changed from perhaps being less conservative to more conservative now that you have this big deal behind you?
That's a good question, Kerr, and I'll tell you, we're going to continue to be opportunistic. 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 first mover status on this kind of horizontal development, we're going to continue to push the envelope on acquiring additional assets. 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. Sticking with the acquisition for now, given that there was some EBITDA associated with the purchase, could we potentially see you guys issue debt to fund the acquisition or any color you can provide there?
Sure. I think, Kerr, what we're doing is we're evaluating all of our options. As it sits today, we expect that we'd probably do a combination of taking advantage of the cash on hand, which Teresa talked about, borrowings under our credit facility, which as I mentioned, are currently undrawn, or proceeds from some kind of offering of securities. Likely a combination of those three things.
Okay, great, last one from me, moving over to the operations. For this 432H 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. 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. Yeah, sure. Good question, Kerr. What we attempted to do on that well is we had its sister well, the 43.1, 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 slick water. In fact, all the wells we've done besides this one have been slick water fracked. What we wanted to do is experiment with a hybrid frac technique where you start off with slick water and you follow in with the linear and crosslink systems. That's what we did on that 432H. 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.
We're struggling to try to figure out exactly, is that a function of the gel system that we put in it, or is there something going on down hole, or could there, in the reservoir, or could there potentially be something mechanical? I'll tell you, we're uncertain enough about it right now that you won't see us doing any more hybrid jobs in the near term.
Great. Thanks, guys.
You bet. Thank you, Kerr.
Our next question is from Mark Lear from Credit Suisse. Your line is open.
Thanks. I guess just a little bit more on the inventory front, I guess with the Spraberry locations and other stack pay, can you talk about when you're thinking about drilling a lower Spraberry well and, I guess, de-risking some of the other zones across your asset base?
Yeah. Mark, I think the most likely next test would be a Spraberry well in the second half of this year. We're in conversations right now with some of our partners to maybe potentially get a Spraberry well on the board before the end of the year.
Okay.
The other zones, it's hard to look at a Wolfcamp A well that's plus 1,500 barrels a day right in your backyard and not be encouraged to go and try that. We're looking at our mapping and picking some locations right now, but that may be a late this year, early next year type of test.
Okay. On the deal, can you talk about the acreage split between Dawson and Martin and then any detail on the reserve add?
Yeah, the split of the two acreage blocks. They're two nice contiguous blocks, and both these blocks are perfectly laid out for repeatable 7,500 foot type of horizontal wells. They're really chunky in these two blocks. 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. The other block's about 5,000 acres, and it's just a little south of that. It's immediately east of our existing leasehold in Northeast Andrews County. From a reserve add perspective, there were 34 vertical wells that are producing those 800 odd barrels a day. 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. 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. Just wondering if there's any explanation maybe from a facilities standpoint. Do you expect these longer laterals to demonstrate flatter curves over time. Just wanted to get a sense on the reason for that.
Sure. I wish I could give you a real definitive answer. We've explained the 43-2, which may have something to do with the way we completed it, and it was a longer lateral on the Spanish Trail 7-1. While we're still pleased with it, we also experimented with a slow back technique where we flowed the well back a lot less aggressively, and so that impacted the 30-day rate. We don't really think it will have anything to do with the reserves. Certainly, that's something we're looking at, Mark. As we continue to drive costs down, we still think that it's pretty much a one-to-one relationship between 7,500 foot and even the first 10,000-foot well. It's something we'll pay close attention to.
Got you. Thanks, guys.
Next question is from Eli Kantor from Iberia Capital Partners. Your line is open.
Hey, good morning, guys.
Hey, good morning, Eli.
Just a quick question on LOE. Looks like you posted an impressive quarter-over-quarter decline there. Relative to the 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, 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 flow back water in our frack jobs. That'll take some water handling out of the equation, and that'll be another potential stair step change in LOE. The other thing is we're still with the third rig, we're working right now on the fourth rig that'll arrive in the fourth quarter. We'll work on the denominator of that unit cost basis as well by increasing volumes.
So, we've been pretty conservative with the numbers we've posted to date, $11 and 30 something cents for the first half of the year. We're going to be at the low end of our full year guidance of between 11 and $13 a barrel, and I certainly expect we'll continue to make improvements on LOE going forward.
That's helpful. Follow-up question from me just on drilling activity as you look into 2014 and 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. We've got three horizontal rigs and only one vertical rig. We're essentially just doing that to try to maintain lease obligations where we can't meet those obligations horizontally. We'll continue to push to drill as few vertical wells as we need to and focus mostly on our horizontal. We're certainly all in on horizontal development.
Okay. Thanks, guys.
The next question is from Richard Tullis from Capital One. Your line is open.
Morning. Travis, could you give the current production rate or at least the 2Q exit rate?
Yeah. 2Q exit rate, we were running a little north of 7,000 barrels a day.
Okay. Looking at the newly acquired acreage in northern Martin County, southern Dawson County, 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. Probably now specifically to your question, Richard, we've seen the Pioneer Mabee well, which I think is about 15 miles from our Martin County acreage, 1,500, 1,600, 1,700 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. Using those same mapping techniques, we like what we see in the two Spraberry benches I talked about, as well as the Wolfcamp A and as well as the Cline.
Probably the furthest north most well, other than the well we're flowing back right now is that Pioneer well.
Okay.
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. Given the acquisition, what sort of CapEx range could we expect next year, including drilling on the new area?
Yeah. 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. 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's the current acreage cost are you seeing in Midland County?
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. Those are the same data points that we look at.
Okay. All right. Thanks a bunch.
You bet, Richard.
Our next question is from Jason Wangler from Wunderlich Securities. Your line is open.
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 vertical drilling? Is there anything you need to hold leases or will you even maybe look to support a horizontal as you get that close and get your hands on it?
Yeah, we might look at getting a horizontal well or two drilled there late this year, early next year. Any vertical wells we might drill might be to access 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. The lease obligations aren't so onerous that we're going to have to go up there and drill a lot of vertical wells to keep the blocks together.
Just in general, where do you think on a rough estimate are you as far as held by production for, I guess your, if you call it legacy acreage and then obviously this new stuff too, maybe where those two numbers are just for an idea of the vertical programs going forward?
Yeah, if you look at our legacy acreage, we're around 40% held by production. What was your second part of that question?
Just 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 Ipsit Mohanty from Canaccord. Your line is open.
Hey, good morning, Travis and team. My first question is a broader question on looking at your acreage, wondering if you can say your confidence level about Wolfcamp prospectivity in the counties other than Midland and Upton, that is, Crockett, Ector, and then the western portion of the Andrews County, please.
Crockett County, we're watching what industry's 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. We've got to balance at what point we test a thinner Wolfcamp B to test its prospectivity.
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 right up there against the shelf's edge, and it thins to less than 100 feet on the eastern side. The Clear Fork Shale looks extremely good, which is why we drilled that 7,500 foot horizontal there. We think while what we may not have in Wolfcamp B prospectivity, we've 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 frack done.
Sure. The one on your recent M&A. I believe your production included vertical wells. What gives you confidence about those 69 horizontal locations you've outlined as well as the other prospective zones, A and Cline and all those guys?
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 are 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. When we saw the Pioneer test on the Mabee Ranch, post that really nice number that sort of sold it for us in the Wolfcamp B, confirmed what we were looking at in a map sense. The Wolfcamp B we're really confident in.
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 in the Spraberry, like I talked about. Our confidence obviously has a band of uncertainty around it. We probably are extremely confident about the Wolfcamp B, then follows with the Spraberrys and the A after that, then ultimately the Clines, our order of confidence.
Okay. Well, one last, if I may, on the OpEx. You've obviously done a great job sequentially bringing it down, you still maintain your guidance for the 2013 as before. Is there a reason why you're not thinking of bringing it down or it's
Yeah, 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 will be at the low end of our range, which is $11 a barrel. We averaged in the first half of the year $11, I think $11.38 a barrel, and we've got the second half of the year to go. We just want to make sure that before we start moving our guidance down, that we're going to be able to achieve that guidance. 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 what that cost came in on the 10,000-foot lateral? I think initially, you all were targeting about $9 million.
Yeah, well, actually, we're drilling out plugs, that well's not complete yet, we'll be in that $9 million-$10 million range. I hate talking about a well that's not completed yet. We've got about a half the plugs or two-thirds of the plugs left to drill out on it. As any horizontal well, always operations risk associated with drilling plugs out.
Okay, I understand. Then obviously, you've talked some about some of the things you did a little bit differently on the frack design on some of these wells, like the 43-2. When we're just thinking about your standard completion technique, is it still appropriate to think about it as 300,000 pounds per stage and 250 feet between stages?
That's correct. One of the things that we're always tweaking it. As engineers, we always try to tweak things and make them better. 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 pounds right now, which is typically split about 30/70 between 100 mesh and the 40/70. We're looking at maybe tweaking the amount of 100 mesh that we initiate these fracks with. Again, they're more than substantive changes. They're more just tweaks to our existing model.
Great. Just the last question from me on the Longhorn Pipeline, I think you all were targeting by the end of the third quarter to sort of be at your full capacity, getting up to the 8,000 gross number. Is that still on track?
Yeah. Again, we're not in control of our destiny there. That's a function of the pipeline and how quickly they can get up to their full capacity. Longhorn Magellan has repeatedly talked about late third quarter, early fourth quarter being at their full capacity. 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. We've been prorated May, June, and July. It's around 1,500 to 2,000 barrels a day. It won't be until that pipeline is at full capacity of 225,000 barrels a day, that we'll 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 McDow from Peregrine Investments. Your line is open.
Hey, guys. 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. Do you have an expectation on EUR for that? I know it's still early stage.
Yeah, I think the real numbers, I think we've quoted 126 or something, but just from an EUR perspective for a long lateral, we'll be in that maybe 500,000 BOE -600,000 BOE range. Again, we've not drilled one yet. Just based on what we're seeing out of that one data point for a 7,500 foot lateral, that's what we think. Again, as I mentioned, though, the development costs, since it's shallower and I actually eliminate a casing string, are going to be quite a bit less. 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. Regarding operating costs, in your presentation, you gave some well economics for horizontal wells. Does $10.15 LOE, is that below or in line with the operating costs you guys were using to calculate those well economics? How does that compare?
That'll be a little bit below. Our actual performance will be a little bit below what we're using in the economics. That'll actually improve the economics. Again, in 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&A, they're further down the list of importance.
Got you. I guess the last question from me, correct me if I'm wrong here, I thought you mentioned 300 gross locations for the acquisition. You mentioned 85 Wolfcamp B. Did you have an estimate for what Wolfcamp A and Spraberry would be out of that 300?
Yeah, we didn't provide that during the call, and actually, I don't have that in front of me, Mark, I'm sorry. We'll just have to get back with you on that.
Okay. Thanks, guys. That's it for me.
Yeah, 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. It's the same rock. On a percentage basis, if you want to just get a rough estimate, you could do the same thing, that's in our pitch book as well.
Got it. Perfect.
Just how 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. That's obviously accretive not only to rate of return, but cost to develop as we continue to post these nice lower well costs.
If you have a question at this time, please press star one on your touchtone telephone. Our next question is from Ryan Oatman from SunTrust. Your line is open.
Hi, guys. Thanks for taking the 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 Wolfberry assets and what that tells you about the productivity of this acreage.
Yeah. 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 130-140 MBO range, which actually are going to generate pretty nice economics at our development cost. Again, as I mentioned, we didn't acquire this asset for vertical wells, but we do have a nice inventory of economic 20%-30% rate of return type of investments up there as well.
Right. Then kind of a random question here on spacing. I see that some of the location counts are based on a 160-acre 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.
Yeah. We're obviously very interested in the results of those tests as well too. I hope those tests prove productive and down-spacing is something that I can talk to you guys about in the upcoming quarters. Where we sit right now, I don't know if you want to call it conservative or not, but we've got six across the section for the Wolfcamp B, and in a general sense, only four across the section for all these other horizons. I hope industry proves up the 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 the late-night emails and early morning emails, I know this is a busy time for you, I appreciate the interest that you guys have in Diamondback Energy and participating in today's call. We really appreciate the call today. Thanks, everybody.
Ladies and gentlemen, this does conclude today's conference. You may now disconnect. Everyone, have a great day.