Thank you, Mercy. Good morning and welcome to Diamondback Energy, 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, participants may make certain forward-looking statements relating to the company’s financial conditions, 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 we 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 reconciliation 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 all of you for listening into 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% over 1,800 barrels a day from the first quarter.

We’ve generated execution results; we believe we 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 perspective Diamondback’s acreage is within this play.

We are seeing impressive well hedge from other operators in northern Midland Basin, which looks to the expanding in play towards where we now have over 29,000 net acres including our recently added position. Our private operator reported results from a lowest Spraberry horizontal well located within 1.5 miles of our Midland County acreage which tested over 630 barrels a day from a short lateral.

As a result, we’ve increased our horizontal inventory by 126 locations in this Spraberry. Pioneer who operated first Wolfcamp A the first reported Wolfcamp A bench test in Midland County, has also shown potential along with their may be Wolfcamp B well location in Martin County both of these Wolfcamp wells posted impressive production rates.

These are key wells and expanding the vertical section and the area withstand for the Midland Basin shales. As I have said before, we intend to be fast followers as the industry continues to deliver promising reserves 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 Spanish Trail 43.1 at 1,136 barrels a day and we now have the 30 day average rate of 916 barrels a day both of those are equivalent rates.

In Upton County the Jacee A Unit 1H had peak IP of 1,085 barrels a day and a 30 day average rate of 632 from the 7,500 foot lateral along with two Janey short lateral wells the 2H and 4H with the peak IPs of 930 barrels a day and 880 barrels a day respectively. When we reevaluate 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 will touch on later.

As a reminder, we have guided towards 550,000 to 650,000 barrels reserves for 7,500 foot lateral again on an equivalent basis. We are currently running three horizontal rigs one in Upton and two Midland County with the fourth rigs scheduled to arrive during the fourth quarter.

Our 23 horizontal wells in various stages of development and over 100,000 feet of lateral footage drills 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 average 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 and reached TD in 14 days along with our very first 10,000 foot lateral which reached TD in 19 days to a measured debt of 19,620 feet. This well has been completed and we're currently drilling out frac loads.

We drilled and completed Janey 4H in Upton County at a total cost of $4.8 million, our first $75 million short lateral. Our second quarter well cost for short laterals were $5.3 million which represents a 12% improvement over the first quarter of 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 in established plans for 2014.

With these impressive execution results, we are seeing well costs migrate to the low end of our guidance of $7.5 million to $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 this pad wells, we anticipate as much as $400,000 to $500,000 savings per well utilized in this zipper frac methodology. With regard to our vertical program, we've seen improvements again this quarter with spud to TD times decreasing by 11% to 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 your Andrews County leasehold with horizontal wells drilled now both in the Wolfcamp B and in the Clearfork Shale intervals. We just completed the 4,000 foot lateral Wolfcamp B well with 19 stages using slick water and flowback operations are underway with the well just beginning to cut off.

We will begin the 7,500 foot Clearfork frac next week. We were pleased with our drilling results since we reached TD in 19 days for the Wolfcamp B wells and 17 days for the Clearfork well, both of which appeared to be among the fastest 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 oil production on time, we’ve released [rental] gas process and 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 are 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% 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 exploit northern Midland Basin shales across multiple benches.

In addition to the Wolfcamp B, we believe the acreage is also prospective in the middle and the lower Spraberry, the Wolfcamp A and the Cline also sometimes refer to as the Wolfcamp B. As these other intervals become derisk, we believe we can add potentially over 300 horizontal locations to our [Jilbore in Missouri].

Approximately 85 locations are Wolfcamp B which expands that inventory by 26% to over 400 locations and increased 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 $14.5 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 reported 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 realization. Our average prices before the effect of hedges were $75.70 per Boe, an improvement of approximately 13% when compared to $67.9 per Boe for the prior quarter.

Our average realized price including the effect of hedges was $74.27 per Boe compared to the $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 cost, our lease operating expenses were $10.15 per Boe as compared to the $12.16 per Boe in the first quarter of 2013, a 20% decrease. Our general and administration 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 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 was $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 LOF pricing on $100.22 for 12 months beginning July 2013. We continue to look 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, Tracy. To summarize we feel we’ve generated great 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'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 drawn 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.

Leaving the acquisition question 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's in the same ball park as the 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 question, 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 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 frac job, except we actually spread the inner stage just inside a little bit.

So I think it's important to note that we're not going to kind of counter the industry by spreading out the actual 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 sand plays and water plays in a 10 stage job as we did in a 19 stage job.

And the implications certainly if we validate that we have not done anything to the EURs, because we're pretty confident now on IP perspective; the implications are more on a cost side. We save probably $300,000 to $400,000 just on the frac ticket alone by spreading these stages and then we’ve got the other ancillary cost with wireline and frac plug etcetera that also add some additional cost savings.

So the implications are more on the cost side then they are on the reservoir performance side Ryan.

And then vertical well cost also coming down about 1.9 last quarter versus your 2 million to 2.2 million guidance, what's driving that reduction is it drilling days, is it better availability of rigs or cruise?

Yeah. It’s really a combination, as I pointed out some of these wells, these guys got them drilled in six point something days, less than seven days.

So there is certainly a drilling efficiency piece to that component as well. And then we are also continue 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 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 cost down to where they are at today.

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?

Yeah, it does Ryan 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 are saving money on all these wells also, which is kind of why we’ve left our CapEx guidance unchanged. So certainly we continued in performance, our stock per pound is going to continue to be impressive.

I think we’ve got 18 wells between now and end of the year on the board right now that we got to drill and complete.

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

Yeah, the Clearfork drilled really good, I mean they got a 7,500 foot lateral drill up there in 17 days. So the drilling really went for the first well up there, it went extremely well.

So really pleased with that and as I mentioned we are going to start fracing that well next week, and then the Wolfcamp B well Ryan, we just start flowing it back, it just start to cut only a couple of days ago, so really, really early times.

I think towards to the A and B market here, obviously great to have this acquisition behind you. I am curious having this acquisition behind you may change your perspective for continuing to acquire lease hold, ensuring quarters specifically, and how your prep change perhaps been less conservative to more conservative now that you have this big deal behind you?

That is good question, Kerr, and I tell you we are going to continue to be opportunistic. I mean we have got the financial firepower to do deals, and if we think these deals are creative to what we currently have in our inventory, we can take advantage of our first mover status in this kind of horizontal development.

We are going to continue to push the envelop on acquiring additional assets. But again I want to stress that we are going to be opportunistic and we are going to always balance those opportunities against our existing inventory and make sure being accretive every time we are doing these deals.

And then you are kind of sticking with acquisitions for now. Given that the [words] of 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 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 are currently undrawn, or proceeds from some kind of offering of security.

So likely a combination of those three things.

Last one from me, kind of move on in to operations. For this 4302H well in Midland County, it looks like on a lateral link adjusted basis it may have come on a little bit weaker relative to some of the other strong wells out there.

And I'm curious if there’s anything specific to this well before [highlighting] that may have been a cause for a slight under performance relatively.

Yeah, sure. Good question Kerr.

What we tend to do on that well is we had its sister well, the 4301, which is mainly adjacent to it, and we thought that be a good opportunity early on in a programs 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 frac.

But what we wanted to do is experiment with hybrid frac technique, where you start off with slick water and you follow in with linear and cross link system. And that's we did in a 43-2H 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 or is there something going on down hole, or in the reservoir or could there potentially be something mechanical. But I'll tell you we're uncertain enough, better right now that you won’t see us in any more harbor jobs in the near-term.

I guess just a little bit more on the inventory front. I guess with the Spraberry locations in other stacked play, I guess can you talk about when you are thinking about drilling a lower Spraberry well and I guess you are risking some of the other zones across your asset base?

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 well partners to maybe potentially get a Spraberry 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 1,500 barrels a day, right in your backyard and not being encouraged to go and try that but we're looking on our mapping and picking some locations right now but that maybe late this year and early next year it is.

On the deals, can you talk about the acreage split between Dawson and Martin and then any detail on the reserve adds?

Yes, the split of the two acreage blocks and the two nice contiguous blocks and they are perfectly, both of these blocks are perfectly laid out for repeatable 7,500 foot type of horizontal wells. So they are really chunking in these two blocks and the Dawson County block is about 6,000 acres and it's wide on the county package, the Austin County, Martin County line and the other blocks about 5,000 acres and is it’s just a south of that its about, it’s a majorly east of our existing lease hold in Northeast Andrews County.

And then from a reserve add perspective there were 34 vertical wells that are producing those 800 barrels a day and Mark, I’ll have to get back with you on the reserve component of those wells, I don’t have it 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 is any explanation maybe from a facilities standpoint, I laterals to demonstrate a flatter curves overtime and just kind of want to get a sense on the reason for that?

Sure. And we think I can give you a little definitive answer, I mean we’ve explained, the 432 which may have something to do with the way we completed and it was a longer lateral this Spanish Trail [71] why we are still pleased with, we also kind of experiment with a flowback technique, where we slowed the well back a lot less aggressively and so that impacted the 30-day rate, that only think we need to do with the, we’ll have anything to do to reserves but certainly that’s something we are looking at Mark.

I mean, we continue to drive cost down, we still think it’s a pretty much 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.

Just a quick question on LOE, it looks like you posted in an impressive quarter-over-quarter decline there but relative to the peers it looks like it 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, these are one of those numbers that I think that I think we have talked before Eli that we never early satisfied as a number; we think there is always opportunity to drive cost out of equations. I will add in my prepared comments kind of those major leverage that we cranked on to get to the status we are right now, we have got one more and probably major level we are crank on which is recycling the flowback water in our frac jobs and that will take some water handling out of the equation and that will be another potential stat change in LOE.

And then the other thing is we are still with preferred rig, we are working on that on the fourth rig that will arrive on 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 in the numbers we have posted today $11.37 for the first half of the year.

We are going to be at the lower end of our full year guidance between $11 and $13 a barrel and I certainly expect, we will continue to make improvements on LOE going forward.

Okay, that is helpful. And follow-up question from me, just on drilling activity as you look into 2014 and beyond, should we anticipate moving towards a 100% horizontal drilling next year is that something that might happen later on down the road?

Well, when you look at the company of our size, we are almost there right now, I mean we got three horizontal rigs and only one vertical rig and so the vertical rig, 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 of our vertical wells as we need to and focus mostly on our horizontal.

But we're certainly all in on horizontal development.

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

Yeah. 2Q exit rate, we are on a little North of 7,000 barrels a day.

Okay and looking at the newly acquired acreage in Northern Martin and 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 resources plays, one of the reasons that they call the resource plays, because the way that these assets are deposited, they had large regional extent to the place. 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, 1,500, 1,600, 17,000 barrels a day out of the Wolfcamp B.

We've map that Wolfcamp B from our Midland County acreage of to that well up in the Andrews County where we got the wells background now into this newly acquired acreage and we like what we see. And using our same mapping techniques, we like what we see the two Spraberry benches I talked about as well as the A and as well as the Cline.

So probably the furthest northmost well other than the well we're flowing back right now is at Pioneer well and there has been some Wolfcamp A activity in and around our area up there, but 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 is a lot of interest at what our 2014 CapEx is going to be, but you’ve got away from until about November when I rolled 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 for 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 that 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 our stream Resolute and the Pioneer deal down in the JV area.

So those are the same data points that we look at.

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?

For this year, will there be some vertical drilling? Is there anything you need to hold [leases] or will you even maybe look to sort of horizontal as you in fact close and kind of get your hands on it?

Yes, we might look at horizontal, given the horizontal well, to drill there late this year, early next year. Any vertical wells we might drill might be to access a little some signs, but at this point right now, we are still putting our full development plan together as respect to timing of one more get up and drill, but the lease obligations aren’t so on us that we are going to have to go up there and drill a lot of vertical wells to keep the marks together.

And just in general, where do you think on a rough estimate RE as far as held by production for I mean I guess your if you call it legacy acreage and then obviously the new stuff to maybe where those two numbers already from an ideas of the vertical programs going forward?

Yeah. If you look at our legacy acreage, we are around 40% ahead of our production.

And in the other part, what was your second part of the question?

Just understand the new acres that you are acquiring, do you have a rough estimate there?

It’s about 30%.

That’s helpful. Thank you.

Good morning, Travis and team. Just my first question is a broader question; I am looking at your acreage, wondering if you can say your confidence level about Wolfcamp prospectively in the counties other than Midland and Upton that is Crockett, Ector and the western portion of the Andrews County please?

Yeah, Crockett County, we are watching what industry is doing down there not on the Wolfcamp B, but some other benches are being tested down there as well too. We are going to be a fast forward down there.

Those leases are still in their primary term. So don’t expect us anytime soon to drill the horizontal well down there unless industry data materially changes.

We might go down (inaudible). Ector County, 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 have got a kind of balance at what point we test the thinner Wolfcamp B to test its prospectively.

And in the western side of Crockett County -- I am sorry the western side of Andrews County that block that is close to the [Shalesage], the Wolfcamp is absent almost right up there against the Shalesage and thin is less than 100 feet on the eastern side, but the Clearfork Shale looks extremely good which is why we drilled that 7500 foot horizontal layer. So we think while we may not have the Wolfcamp B prospectivity we more than made up for in the Clearfork and we will test that here in the next couple of weeks when we get that frac done.

And then the one on the recent M&A, I believe your production to drill vertical wells, so what gives you confidence about those 69 horizontal locations you have outlined as well as the other prospective zones in Cline?

Yes, and certainly there is a greater confidence across all the other zones, but today we looked at that has most excited in Wolfcamp B and we were excited about that Wolfcamp B prospectivity both from the thickness that has been positive 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 sell force in the Wolfcamp B.

So kind of confirmed that we were looking at in the (inaudible). So that Wolfcamp B, we are really confident in and then Wolfcamp A, again even though it's probably 60 miles away down in Midland County that other drilling Nashville Camp A well, again resource basin like these shales are out here in the Midland Basin.

They run there nearly for a very long way and we like what we see in the Wolfcamp A and in Spraberry and like I talked about. So our confidence obviously has been of uncertainty around it, we're probably extremely confident about the Wolfcamp B and then we follows with the Spraberry and A after that and then ultimately declines kind of our order in this confidence.

Okay. Well, one last if I may on the OpEx, that you have kind of obviously done a great job sequentially bringing it down, but just to the maintaining your guidance for the 2013 as before, is there a reason why you're on kind of thinking of bringing it down or it's?

Yeah. I think the words I used it’s in my prepared remarks was that we're going to be at the low end of our range for the full year guidance, for our full year performance will be at the low end of our range, which is $11 a barrel.

And we average in the first half of the year, $11, I think $11.38 a barrel and when we got in the second half of the year ago. So, 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.

So right now just be confident that we're communicating at the low end of that range.

We will be. Thank you

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 targeted about 9 million?

Yeah. We're still -- actually we're drilling out plugs, so that well is not complete yet.

But we'll be in that $9 million to $10 million range, but (inaudible) talking about wells not completed yet. So we got about half the plugs or two-thirds of plug left to drill out on it.

So as horizontal well there’s always operations risk associated with drilling plugs.

Okay, I understand and then obviously you’ve talked about some of the things you do a little bit differently on the fact design on some of these wells like the 43-2. But when we're just thinking about your standard kind of completion technique, is it still appropriate to think about it as 300,000 pounds per stage and 250 feet between stages?

That’s correct. And one of the things that 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 300,000 pounds right now which is typically split 30-70 between 100 [mesh] and a 40-70. We're looking at maybe tweaking the amount of 100 mesh that we initiate these fracs with, but again they are more than substantive changes and more just tweaks to our existing model.

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

Yeah, 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, and Magellan has repeatedly talked about late third quarter, early fourth quarter being at the full capacity but what I have said as an operator contributing volumes to that pipeline.

It's been a little slow in the uptick on getting up to that full capacity. So we've been prorated, May, June and July it’s around 1,500 or 2,000 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.

Most of my questions had been answered, but I do have a few more regarding inventory. You mentioned 120 of gross inventory for Spraberry; do you have expectation on EUR for that, I know it’s still early stage?

Yeah. I think the real numbers, I think we’ve quote a 126 or something but just from an EUR perspective from a long lateral we’ll be in that maybe 500,000 to 600,000 BOE range.

We’ve not drilled one yet, so just based on what we are seeing out of that one data point for 7,500 foot lateral that’s kind of what we think. Again as I mentioned those development cost since it is shallower we are going to actually eliminate (inaudible) are going to be quite a bit less.

So from cost to develop just how we look at some of our investments its going to be competitive with the Wolfcamp B.

Then regarding operating cost, in your presentation you gave some well economics for horizontal wells, does $10.15 LOE when you are running, is that below or in line with the operating cost you guys were using to calculate those well economics, and how does that compare?

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

Last question from me, correct me if I am wrong here but I though you mentioned 300 gross locations for the acquisition. You are missing the 85 Wolfcamp B, given an estimate for Wolfcamp A and (inaudible) would be, above 300.

Yeah, we didn’t provide that during the call, but its and that actually I don’t have that in front of me Mark I am sorry, so we’ll just have to get back with you on that. 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, I mean it’s the same rock, so count it on a percentage basis, if you want to just get a rough estimate, you can do the same thing and that’s in our pitch book as well.

You mentioned on the calls and since you referenced that slide in our pitch book. The fact that we have been able to mark these cost down sequentially have got in our pitch book for $100,000 we knock off our well cost.

We improve our cost to develop by $0.25 a barrel so that’s accretive not only on regular term but cost to develop as we continue to post these nice lower well costs?

I wanted to ask on this acquisition, there is some vertical well production on it. I was just curious how those wells are performing say to your typical type curve for your Wolfberry assets and what that tells you about your perspective to the productivity of this acreage?

Yeah. Relative to what we typically see from vertical wells, those wells in Martin County, which is where the majority of those verticals wells sit, they are going to be in that 130 to 140 NBO range.

Which actually are going to generate pretty nice economics at our development cost; so, as I mentioned, we didn't acquired this asset for vertical wells, but we do have a nice inventory of economic 20% to 30% rate of return on top of investments up there as well.

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 or 100?

Yeah, and we're obviously very interested in the results of those tests as well [proving]. So I hope those test 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, I don’t know if you are going to call it conservative or not, but we're, 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. So I hope industry proves up to down spacing works, because we're perfectly position to have a material uptick on inventory, if that works.

Thank you, Mercy. I know you guys, judging by a lot of late night emails and early morning emails; I know this is 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.