Diamondback Energy Inc (FANG) 2013 Q2 法說會逐字稿

Good day ladies and gentlemen. Welcome to Diamondback Energy's 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 Lawlis, Investor Relations. You may begin.

Thank you Merci. Good morning, and welcome to Diamondback Energy's second quarter conference call. Representing Diamondback today are Travis Stice, CEO, Tracy 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 performances, 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 which we believe provide useful information for investors. We include reconciliations of those measure 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 have ramped production to 6,600 barrels a day, that is up 30% or over 1,800 barrels a day from the first quarter.

We have generated execution results we believe are among the best in the basin, and we have realized operating expense reductions with LOE for the quarter at $10.15 a barrel. And lastly, we have 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 are 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 1.5 miles of our Midland County acreage, which tested at over 630 barrels a day from a short lateral.

As a result, we have 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 have 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 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 7500-foot lateral. Along with two Janey short lateral, the 2H hand 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 l curve projections, and at or below our cost projections, which I will touch on later. As I remainder, we have guided towards 550,000 to 650,000 barrels of reserves for a 7.500 foot lateral, again on an equivalent basis. We are currently running 3 horizontal rigs, one in Upton, and two in Midland County, with a fourth rig to arrive during the fourth quarter. Our 23 horizontal wells in various stages of development in over 100,000 feet of lateral footage drilled since we began our horizontal program. I am confident that Diamondback is leading the way in delivering strong horizontal well results, and value to our stockholders.

Turning to our quarterly results, we are 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 of 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 are 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 costs for short laterals was $5.3 million, which represents a 12% improvement over 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 are seeing well costs migrate to the low end of our guidance of $7.5 millionto $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 tests 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 will see a slight increase in our POP time, or placed on production time for these pad wells, we anticipate as much as $400,000 to $500,000 savings per well utilizing this Zipper frac methodology.

With regard to our vertical program, we have seen improvements again this quarter with spud to TD times decreasing by 11%, to average of 8 days. Three of these wells reached TD in less than 7 days. Our vertical well costs are now averaging $1.9 million. We have also begun testing the horizontal potential of our Andrews County leasehold, with horizontal wells drilled now both in the Wolfcamp B and in the Clearfork shale integrals. 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 Clearfork frac next week. We are pleased with our drilling results since we reached TD in 19 days for the Wolfcamp B well and 17 days for the Clearfork well, both of which appear to be among the fastest to TD we have seen relative to nearby horizontal drilling activity.

As you can see, we are 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 have reduced LOE by 20%, and represents a reduction of almost 45% from our high during 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 have placed the majority of our water production on pipe. We have released rental gas processing equipment and we have electrified the majority of our leasehold. With the first half of 2013 behind us at an average of $11.38 a barrel, we are well on our way of our goal lower to reduce our total LOE to the lower end of the range of $11.00 to $13.00 for the full year of 2013.

Finally, we are pleased to announce that we have entered in 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 to 30 million 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 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 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 increases our total inventory across all zones to approximately 1,200 gross horizontal locations. I will be able to provide color on how these acquisitions will impact 2014 during our next call in November. But simply stated it is more much 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 $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 gainand 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 volume from our horizontal wells, as well as higher price realizations. 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 realization. Our average prices before the effective hedges was $75.70 perBoe, an improvement of approximately 13% when compared to $67.09 perBoe for the quarter. Our average realized price including the effective 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 & Administrative costs came in at $4.37 per Boe, and in line with our guidance of between $3.00 and $5.00 per Boe. Our production tax and DD&A are both in line with guidance.

At quarter's end we had no debt, and 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 addition oil derivative position of 1,000-barrels per day, at LLF 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 will now turn the call back over to Travis for his closing remarks.

Thank you Tracy. To summarize we feel we have generated very positive results again for the quarter. We are very excited about these acquisitions, because it gives us the opportunity to demonstrate what we do best, execute. We have continued our production ramp, execution is at or near the top in our initial drilling results, expenses are down, development costs on both horizontal and vertical wells continue to trend down, and we have yet to draw or our borrowing base.

On behalf of the Board and the employees of Diamondback Energy, I would like to thank you for participation today. This concludes our prepared comments. Operator, please open the call to questions.

Thank you. (Operator Instructions). Our first question is from Ryan Oatman from SunTrust, your line is open.

Hi, good morning.

Good morning Ryan.

I will leave the acquisition questions for someone else, but I want to talk about your operations here. In Upton County this Janey 4H was completed with only 10 frac stages, but it looks like it is in the same ball park as Janey 2H, which was completed with 19 frac stages. Can you talk about what you are doing there, and the potential productivity implications for the whole play?

Yes, I think just to answer the productivity questions, we are still early in the analysis of that particular frac methodology, but certainly what we have seen from early time data, the IP in the first 30 days we have 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 inner stage distance out a little bit. So

I think it is important to note that we are not going counter to industry by spreading out the actual perf clusters, but what we are really doing is just spreading out how much we can place in each stage. We have 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 have not done anything to the EURs, because we are pretty confident now on an IP perspective, the implications were more on the cost side, we saved 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 wire line and plugs et cetera that will add cost savings. Then we have got the other ancillary costs with wireline and frac plugs, et cetera 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.

Great and then vertical well costs also coming down about $1.9 millionlast quarter versus your $2 million to $2.2 million guidance. What is driving that reduction?Is it drilling days, is it better availability of rigs or crews?

Yes, it is really a combination. As I pointed out some of these wells some of these guys got them drilled in 6-something days, less than 7 days. So they is certainly a drilling efficiency piece to that component as well. Then we also continue to take advantage of surplus of services in some areas out in the Permian, and taking advantage of lower costs. And then lastly I want to give credit to the guys both on the completion and drilling side, to just making sure they scrutinize every cost element, and make sure that we are competitive on every cost element of the AFE, in order to get those costs down to where they are at today.

Okay, then drilling days it does look like they 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 are probably, we probably can get maybe four or five more horizontal wells drilled this year, if we are able to replicate this cadence. But the other side of that is on the cost side. We saving money on all of these wells also, which is kind of why we have left our CapEx guidance unchanged. So certainly with continued end performance our cycle time is going to continue to be impressive. I think we have got 18 wells between now and the end of the year on the board right now, that we have got our drilling complete.

Okay. And then Andrews County, it looks like it is early days with these two wells. Any color on the early production from the Wolfcamp B test, or how that Clearfork drilled?

Yes, the Clearfork drilled really good they got a 7,500-foot lateral drilled up there in 17 days. The drilling for our first well up there, it went extremely well. So really pleased with that. As I mentioned we are going to fracing that well next week. The Wolfcamp B well, Ryan, quite honestly we just started flowing it back. It just started cutting a little a couple of days ago, so really, really early times.

Got it. That is it for me. Thank you.

Thank you Ryan.

Thank you. Our next question is from Kerr Friedman from Simmons and Company. Your line is open.

Good morning guys.

Hey Kerr.

Thinking towards the A&D market here, obviously great to have this acquisition behind you. I am 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 is a good question. We are going to continue to be opportunistic, we have 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 are going to continue to push the envelope on acquiring additional assets. Again, I want to stress that we are going to be opportunistic and I will always balance those opportunities against our existing inventory, to make sure that we are being accretive every time we do one of these deals.

Great. Sticking with the acquisition for now, given that there was some EBITDA associated with the purchase, can we potentially see you guys issue debt from the acquisition, or any color you can provide there?

Sure. I think what we are doing is we are evaluating all of our options. As it sits today we can be expect that we 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 are currently undrawn,or proceeds from some kind of offering of security. Likely a combination of those three things.

Great, and then last one from me, moving over to the operations for the 4302H well in Midland County, it looks like on laterally congested basis, it may have come on a little bit weaker relative to some of your other strong wells out there, curious if it is anything specific to this well that is worth highlighting that may have been a cause for the slight underperformance relatively?

Sure. Good question. What we attempted to do on that well is we had its sister well, the 4301, which is immediately adjacent to it, and we thought that would be a good opportunity early on in the program to do some side by side testing of different frac methodologies. We have always been a proponent of slick water, in fact, all of the wells we have done besides this one have been slick water fraced.

What we wanted to do is experiment with a hybrid frac technique, where you start with slick water, and you follow in with the linear and crosslink system. That is what we did on that 4302H, and the job went exactly as designed. From an IP perspective it looks like it is down quite a bit from its offset well. And we are 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 downhole, or in the reservoir, or could there potentially be something mechanical. But I will tell you that we are uncertain enough 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 Swiss. Your line is open.

I guess just a little bit more on the inventory front with the Spraberry locations and other stacked pay, I guess can you talk about when you are thinking about drilling a lower Spraberry well, and 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 are 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. And then the other zones it is hard to look at a Wolfcamp A well that is plus 1,500 barrels a day right in your backyard, and not be encouraged to go and try that. But we are 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. And then on the deal, can you talk about the acre split between Dawson and Martin, and then anything on the, any detail on the reserve add?

Yes, the split of the two acreage blocks and they are two nice contiguous blocks, and both of these blocks are perfectly laid out for repeatable 7,500 foot type of horizontal wells, so they are really chunky in these two blocks, and the Dawson County block is about 6,000 acres, and it is right on the county, in fact it straddles the Dawson and Martin County line, and then the other block is 5,000 acres, and it is just a little south of that. It is 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 will 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, just wondering if there was any explanation from a facilities standpoint, do you expect these longer laterals to demonstrate flatter curves over time?I kind of wanted to get a sense on the reason for that?

Sure. I wish I could give you a real definitive answer. I have explained the 4302, which may have something to do with the way we completed it, and it was a longer lateral, and the Spanish drill 71, while we are still pleased with it, we also kind of experimented with a slowback 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 had anything to do with the, will have anything to do with the reserves, but certainly that is something we are looking at Mark. As we continue to drive costs down, we still think that it is pretty much a one to one relationship between 7,500-foot and even attempt the first 10,000-foot well. It is something that we will pay close attention to.

Got you. Thanks guys.

Next question is from Eli Kantor from IBERIA Capital Partners. Your line is open.

Good morning guys.

Hey, good morning Eli.

A quick question on LOE. It looks like you posted an impressive quarter-over-quarter decline there. Relative to your 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 have talked before Eli, that we are never really satisfied with the number. We think there is 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 are at right now. We have got one more major lever that we are probably going to crank on, which is recycling this flow back 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.

The other thing is we are still with the third rig we are working right now on the fourth rig that will arrive in the fourth quarter, we will work on the denominator of that unit cost basis as well by increasing volumes. So we have been pretty conservative with the numbers we have posted to date, $11.30-something for the first half of the year. We are going to be at the low end of our full year guidance of between $11 and $13 a barrel, and I certainly expect that we will continue to make improvements on LOE going forward.

That is helpful. Other question from me is just on drilling activity as you are looking at 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?

When you look at a Company our size, we are almost there right now. We have got three horizontal rigs and only one vertical rig. The vertical rig we are essentially just doing that to try to maintain lease obligations where we can't meet those obligations horizontally. So we will continue to push to drill as few vertical wells as we need to, and focus mostly on our horizontal, but we are certainly all-in on horizontal development.

Thanks guys.

Next question is from Richard Tullis from Capital One. Your line is open.

Good morning. Travis, could you give the production, current production rate or at least the 2Q exit rate?

Yes, 2Q exit rate we are running a little north of 7,000 barrels a day.

Okay. Locking at the newly-acquired acreage unless 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 they are called a resource play is because of the way that these assets are deposited, they have large regional extent to the plays. Probably now specifically to your question Richard, we have seen the Pioneer Mabee well, which I think about 15 miles from our Martin County acreage, 1,500, 1,600, 1,700 barrels a day out of the Wolfcamp B. We have mapped that Wolfcamp B from our Midland County acreage up through that well, up into our Andrews County, where we have 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 two Spraberry benches I talked about, as well as the A, as well as the Cline. Probably the furthest northmost well other than the well we are flowing back right now is that Pioneer well, and there has 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?

That is a fair question Richard. And I know that there is a lot of interest to what our 2014 CapEx is going to be, but you have got to wait for me until about November when I roll out my full plan, and we will be able to give you a real wholesome view of what our 2014 looks like at that time.

Okay. And then just lastly from me, I guess this acquisition gives us a pretty good indicator of what the Martin County acreage is going for currently. What is current acreage cost in Midland County?

I mean you look at the same data that we do Richard, we have got a couple of transactions that occurred with RSP and Resolute, and then the Pioneer deal down in their JB area, so those are the same data points that we look at.

Okay. Thanks a bunch.

You bet Richard.

Our next question is from Jason Wangler from Wunderlich Securities. Your line is open.

Good morning. Just curious on the new stuff, what do you see, at least I know you don't have a good feel for next year yet, but for this year will there be some vertical drilling, is there anything that you need to hold leases, or maybe even look to start a horizontal as you get that closed, and kind of get your hands on it?

We might look at on the getting a horizontal well or two drilled there late this year or early next year. Any vertical wells we might drill might be to access a little, some science, but at this point right now we are still putting our full development plan together, as respect to timing of when we will get up there and drill. But the lease obligations aren't so onerous that we are 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 mean at this guess if you call it legacy acreage and then obviously this new stuff too, where those two numbers are just for an idea of the vertical programs going forward?

Yes, if you look at our legacy acreage , we are around 40% held by production, and then, what was your second part of that question?

And then the new acreage that you are acquiring, do you have a rough estimate there?

It is about 30% HBP.

That is 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 in the western of Andrews County, please?

Crockett County we are watching what the industry is doing down there, not only Wolfcamp B but some other benches are being tested down there as well too. We are going to be a fast follower down there, those leases are still in their primary terms, so don't expect us any time soon to drill a horizontal well down there, unless industry data materially changes. We will might go down there and do a core hole. Ector County, Ector County is the eastern side of Ector county our acreage block has some potential in the Cline, and the Wolfcamp B starts to thin over there, so we have got to kind of balance at what point we test the thinner Wolfcamp B to test its prospectivity.

And then the western side of Andrews County, that block that is close to the shelf's edge, the Wolfcamp is absent on the right up there against the shelf's edge, and it thins to less than 100 feet on the eastern side, but the Clearfork shelf looks extremely good, which is why we drilled that 7,500 foot horizontal there. So I think while what we may not have in Wolfcamp B prospectivity, we more than made up for it in the Clearfork, and we will test that here in the next couple of weeks when we get that frac done.

Sure. And then the one on your recent M&A, I believe your production through vertical wells, what gives you confidence about those 69 horizontal locations you have outlined as well as the other prospective zones A and Cline, and all of those guys?

Certainly there is a grade of confidence across all of the other zones, but the data that we have 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 has been deposited up there, but also the resistivity and the porosity. And then when we saw the Pioneer test on the Mabee Ranch post that many really nice number, that sort of sold it for us in the Wolfcamp B, so it kind of confirmed what have we were looking at in a map sense. So Wolfcamp B we are really confident in, and then the Wolfcamp A again even though it is 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 we what we see in Wolfcamp A and the Spraberry, like I talked about. Our confidence obviously has a band of uncertainly around it, and we probably are extremely confident about the Wolfcamp B and then we follow with the Spraberry and the A after that, and then ultimately, the Cline is kind of our order of confidence.

Okay. One last if I may on the OpEx. You have kind of obviously done a great job sequentially bringing it down, but you still maintain your guidance for 2013 as before. Is there a reason why you don't kind of thinking of it bringing it down?

Yes, I think the words I used in my prepared remarks is that we are going to be at the low end of range for full year guidance, 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 $11.38 a barrel, and we have got the second half of the year to go. So we just want to make sure that before we start moving our guidance down, that we are going to be able to achieve that guidance. So right now, just be confident that we are communicating at the low end of that range.

We will be. Thank you.

This 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 all were targeting about $9 million?

Yes, we are still, actually we are drilling out plugs so that well not complete yet. But it will be in the $9 million to $10 million range. But I hate talking about a well that is not completed yet. So we have got about half of the plugs or two-thirds of the plugs left to drill out on it. As any horizontal well, there are always operations risks associated with drilling plugs out.

Okay. I understand. And obviously you have talked some about some of the things you did a little bit differently on the frac design on some of these wells, like the 43-2, but when we are 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 is correct, and one of the things that we may, we are always tweaking it. As engineers we always try to tweak things to make them better. One of thethings that we are looking at tweaking right now is the amount of sand we are trying to place in these wells. We are going at 300,000 pounds right now, which is typically split 30/70 between 100 mesh and 40/70. We are looking at maybe tweaking them at 100 mesh that we initiate these fracs with. They are more than substantive changes, they are more just tweaks to our existing model.

Last question for me on the Longhorn pipeline, I think you all were targeting by the end of the third quarter to be at your full sort of capacity getting up to like the 8,000 gross number. Is that still on track?

We are not in control of our destiny there, that is a function of the pipeline and how quickly they can get up to their full capacity. They have repeatedly talked about Longhorn Magellan has repeatedly talked about late third quarter/early fourth quarter, being at their full capacity, but where I see it as an operator contributing volumes to that pipeline, it has been a little slow in the uptake on getting up to that full capacity. So we have been prorated May, June and July to around 1,500 to 2,000 barrels a day. It won't be until that pipeline is at full capacity at 225,000 barrels a day, that we will be at that 8,000 barrels a day gross number that you referenced.

Great. I appreciate it. Thanks a lot.

You bet John, thank you.

Next question is from Mark McDowell 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 is still early stage.

I think the real numbers, I think we have quoted 126 or something. But just from an EUR perspective from a long lateral, we will be in that maybe 500,000 to 600,000 Boe range, and again that is a pretty, we have not drilled one yet, so just based on what we are seeing out of that one data point for a 7,500-foot lateral that is kind of what we think. Again as I mentioned the development costs since it is shallower and actually are eliminating a [cassion] 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 is 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 $10.15 toLOE when you are running, is that below or in line with the operating costs you guys were using to calculate those well economics, and how does that compare?

That will be a little bit below our actual performance will be a little bit below what we are using in economics, so that will actually improve through economics. But again in what moves a 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 are further down the list of importance.

Got you. And I guess the last question for me, correct me if I am wrong here, but 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?

Yes, we didn't provide that during the call, and actually I don't have that in front of me, Mark, I am sorry. We will just have to get back with you on that.

Okay. Thanks guys. That is it for me.

Mark, Russell was just talking to me there, it is going to very similar to what we have in our existing inventory. It is 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 is in our pitch book as well.

Got it.

And you were mentioning the cost and since you referenced that slide in our pitch book, the fact that we have been able to knock these costs down sequentially, I have got in our pitch book for every $100,000 we knock off our well costs, we improve our costs to develop by $0.25 a barrel. So that is obviously accretive not only to rate of return, but cost to develop, as we continue to post these nice lower well costs.

Thanks.

(Operator Instructions). Our next question is from Ryan Oatman from SunTrust. Your line is open.

Hi guys thanks for taking the follow-up here. I wanted to ask on this acquisition there is some vertical well production on it. Was just curious how these wells are performing say to your typical type curve for your Wolf area assets, and what that tells you about the prospectivity of this acreage, productivity of this acreage?

Relative to what we typically see from vertical wells, those wells in Martin County which is where the majority of those vertical wells sit, they are going to be in that 130 to 140 Mbo range, which actually are going to generate pretty nice economics at our development costs. So again as I mentioned, we are 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 160-acre spacing, is there a chance to for that to move down?I know some of the other folks in the basin are testing 60s 80s, 100?

Yes, and we are obviously very interested in the results of those tests as well too. So I hope those tests prove productive and down spacing is something that I can talk of talk you to guys about in the upcoming quarters, but where we sit right now, I don't know if you want to call it conservative or not, but we have got 6 across a section for the Wolfcamp B, and then in a general sense only four across a section for all of these other horizons. So I hope this industry proves up that downspacing works, because we are perfectly positioned to have a material uptick in our inventory if that works.

Great. That is it for me.

Thank you. We have no further questions. I wouldnow like to turn the call over to Travis Stice, CEO, for closing remarks.

Thank you Merci. 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, and 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.