Good day, ladies and gentlemen and welcome to the Diamondback Energy’s Second Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time (Operator Instructions) as a reminder, today's call is being recorded. I’ll now turn the conference over to Adam Lawlis, Investor Relations. Sir you may begin.

Thank you. 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, VP of Reservoir Engineering. During this conference call the participants may make certain forward-looking statements relating to the Company’s financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can 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 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’s second quarter 2014 conference call. Since our last call, we’ve issued an operations update that highlighted our pending leasehold acquisition primarily located in Midland and Glasscock Counties in the core of the Northern Midland Basin, increased our full year production guidance, successfully completed our Southern most test of the lower Spraberry in Upton County and that we have placed on production the best horizontal well on a per lateral foot basis in the Midland Basin. Switching to second quarter results, we continued our production growth by growing volumes over 170% as compared to the second quarter of last year and 32% from the prior quarter. We continue to expect to grow production by nearly 150% in 2014 as compared to 2013. This would mark the second consecutive year of nearly a 150% production growth. Our operating expenses continue to be within guidance, but with nearly 300 gross vertical wells acquired this year. We would expect cost to migrate towards the high end of guidance in the near-term as we optimize these wells consistent with our prior practices. Our low cost structure combined with high ore cuts continues to drive peer-leading cash margins. We have several significant wells in various stages of the development throughout our leasehold in the Midland basin. We drilled our first lower Spraberry well in Martin County, our first Cline well in Dawson County and our first stacked Wolfcamp B, lower Spraberry well offsetting our Gridiron well in Midland County. All are awaiting completion operations to begin in the next several weeks. Additionally, we are testing increased frac density in Midland County on two adjacent 5000 foot lateral wells using our standard 22 stage designs on one and an increased density frac design at…

Thank you, Travis, and welcome everyone. I’ll provide a quick overview of the financial highlights. Our net income for the second quarter was $27.8 million or $0.54 per diluted share versus net income of $14.5 million or $0.36 per diluted share for the same period in 2013. Adjusted net income for the quarter included a loss on commodity derivatives of $11.1 million and a loss on sale of assets of $1.4 million. Excluding the losses and the related income tax effect are adjusted net income with $35.8 million or $0.70 per diluted share. As previously reported our production for the second quarter was approximately 17,836 boe per day. These volume generated revenues in the second quarter of $127 million compared to $45 million for the same quarter in 2013. Realized pricing for the second quarter before the effective hedges was $78.25 and with the effective hedges it was $76.02. Our average realized oil prices before hedges was $95.90 and with the effective hedges it was $92.20. Our EBITDA for the quarter was $103 million. Turning the cost, our LOE was $6.47 per boe in the second quarter. Our general and administrative cost came in at $2.42 per boe which includes non-cash stock based compensation excluding stock based compensation SG&A cost or $1.73 per boe. Our current hedge position through 2015 have been laid out in our earning release. We currently have about 40% of our estimated crude oil production hedged for the reminder of 2014. We continually affect our hedging opportunity and we intend to continue to layer on additional hedges at our production growth. In the second quarter of 2014 we generated $87 million of operating cash flow and $85 million of discretionary cash flow for $1.70 and $1.66 per diluted respectively. During the second quarter of 2014, we spent $124.1 million for drilling completion and infrastructure. Our liquidity position remains strong with approximately $37 million cash on hand at June 30, 2014 and we had drawn $46 million on our secured revolving facility which had a borrowing base of $350 million. We have subsequently reduced the outstanding balance to zero with a portion of the proceeds from our equity offering in July. I will now turn this call back over to Travis for his closing remarks.

Thank you Tracy, to summarize we are again adding acreage in the quarter Northern Midland Basin play and we've recently increased production guidance for the second time this year. I'm proud of our continued success in driving production growth, continued improvement executed on these complex well pads and confirming new zones like Lower Spraberry in Upton County include Clearfork Shale in Andrews County. I believe we continue to deliver results and stock holder returns that are among the best in the Midland Basin. Before I open the call for question, I want to acknowledge our employees on all they have accomplished in the first half of this year and especially welcome those employees that are new to Diamondback. On behalf of the board and employees of Diamondback Energy, I would like to thank you for your participation today. This concludes our prepared comments. Operator, please open the call to questions.

Thank you. (Operator Instructions) Our first question comes from David W. Kistler of Simmons & Company. Your may begin.

Good morning guys.

Good morning Dave.

Real quickly, looking at the Martin County Wolfcamp B results and the Andrews County Clearfork results, can you talk a little bit about what that does or increasing development inventory on a longer term basis and then those might fall in terms of competing for capital as you go forward with development?

Sure Dave and thank you. I think in my prepared remarks I actually referenced those Wolfcamp B wells and Midland County and of course they are in Northern Martin County, so I apologize for that misspeak there, but specifically almost Martin County wells now this is the second and third well and we are confirming kind of that reserve target of between 650,000 and 700,000 barrels of oil equivalent and that’s going to place these in that 50% to 60% rate of return. So it’s really time for us to go to work there now. We've got three wells that are spread across the acreage, it really confirms the viability of Wolfcamp B, so I think you know it’s logical to assume that we will partner rig there and really focus on well-to-well efficiencies. Now moving over to the Clearfork Shale in Andrews Count, you know as I mentioned those well costs are going to be around $6 million. I actually think as we get in there with reputable wells we can drive those costs down, but as it sits right now to $6 million well cost that Clearfork Shale is going to be somewhere between 30% and 40% rate of return and you know probably 450,000 to 500,000 boe of oil equivalent basis. And while 30% to 40% rate of return is still a goodwill that certainly doesn’t compare when you look at the plus 70% to almost 100% rate of return included the fact, the minerals we are getting in the county. So we don’t expect just to get out there and just start drilling one well right after another, but we probably got about 50 to depending on spacing you know maybe over 50 locations in the Clearfork Shale, but what I think is more logical is that you will see us early next year, maybe late this year move back into there and drill a two well pad and see if we can get some cost efficiencies on a two well pad and improve the economics there.

Great I appreciate that and then maybe switching to something a little bit different one of your peers recently contracted or bunch of water sourcing looking forward and talked about what their water needs will be for drilling completions over the next 10-years, obviously in ways away, but can you talk a little bit about how you are handling the water situation right now and how that factors into the rig ramp that you outlined for us getting to kind of 9 rigs plus 16?

Sure Dave. What we’ve done is gone through each of our development areas and put in place what we call a water usage plan and that water usage plan is sort of the holistic approach to access, accumulation and disposal of water. And we really got to be effective in addressing each of those three things for each of our asset areas, because once we have a real well laid out strategy for those three items then we go in and put rigs on top of that. And I think we are going to need all sources of stimulation water going forward, whether it’s existing fresh water, Brackish Santa Rosa water or recycled water in order to match our rig need. So it’s an issue that we are paying real close attention to and trying to make sure it’s consistent with our development strategy.

Great appreciate that and then just as long as we are on things that could be potential bottlenecks going forward. What are the other bottlenecks that kind of concern you as you look at this aggregated portfolio and how you develop it going forward?

Well, there is in fact in a journal yesterday there was a nice article on sand and you are seeing more and more sands being used in our industry whether it’s in Eagle Ford or the Bakken and even in our own backyard where we’re talking about increasing 6 million pound job up to 9 million pound job. To the extent that the industry migrates towards more and more sand in these horizontal wells, I think its realistic that we've got to make sure we've got this you know the full supply chain figured out to make sure we and our services companies can access the sand at the time we need it and then between sand and stimulation water those are the two things that I think about.

Okay great. I really appreciate the clarification. Great work guys.

Thank you Dave.

Thank you. Our next question comes from Gordon Gouthat of Wells Fargo. You may begin.

Thanks good morning everybody. Just to dough tail off of that last question, so recognizing it’s a bit earlier in the Permian delineation, but there has been a lot of talk recently about evolution and completion design and since you mentioned about increasing prop and how are you thinking about the evolution of your completion designs going forward.

Well, Gordon we’ve always continued to tweak our completion designs and always looking for ways to extract more rollout of this rock at a competitive price. Just as an aside, I know there's a lot of communication in the industry now about the effective slick water fracs. Well, we did our first horizontal well over two years ago down in Upton County, as one of the first operators to start drilling horizontal wells in areas that have are predominantly drilled vertically. And that first horizontal well was slick water job and that's really and we've got over 80 of them completed and I think 79 of them have had slick water frac or applied to it. So we continue to tweak sand per foot, water per foot and in this most recent test we're going to try to hold as many variables constant as we can and just increase the number of stages across the lateral and that's that 22 stage going up to 33 stage and we're doing it on a sister well. So it's a pad well and one well with 22 stages and then just immediately over we'll do the next well with 33 stages and we think that will give us the best way to measure our improvement. It’s about $3 million more pounds of sand. It's probably going to cost us about a million barrels, but if we can pick up a little more than million dollars, if we can pick up about 10,000 more barrels on EUR, it will probably pay for it. So just look for us to provide more color as we go forward.

Okay. That’s helpful. And then a question Travis, you mentioned in your comments at prepared remarks that the rig allocation this year and as you had rig next year I'm just wondering how you look to allocate those rigs across the various areas of your position?

Yes, you know we talked in our operations about a couple of weeks ago about on the newly acquired acreage and we think we'll have a rig-and-a-half on that new acreage. So there's 1.5 rigs there, the other rigs – we're going to try to keep as many rigs as we can in our Spanish Trail acreage where Diamondback owns 93% of the minerals there now. We'll try to keep this many there; we’ll keep one rig down in Upton County that’s why I was extracted about this new Lower Spraberry well that gives us some good opportunities there. One of our competitors talked about a nice Cline result down in Upton County as well, which we haven't testified, but obviously we'll pay close attention to there. So, two- three Midland County, two-three in the Northern blocks, one and half in our newly acquired acreage and one or so down south, will get you kind of into that 7.5, 8 rig cadence.

Okay, and then, under that program, any preliminary thoughts on how the growth profile would trend?

Gordon we've not signaled yet what our 2015 is going to be. I think we have a November call scheduled and that's when we'll have a more fulsome discussion on 2015.

Okay, thanks a lot guys.

Thank you, Gordon.

Thank you. Our next question is from Mike Kelly of Global Hunter Securities. You may begin.

Thanks guys good morning. Travis, I was hoping you can talk about the opportunity set for Viper you guys are really kind of first mover here with throwing the mineral rates and MLP. I was just hoping if you could talk about that and then also curious if there is beyond just being a 92% owner of Vennum, is there is any other added benefits that might not be obvious for FANG’s holders having that MLP in place. Thanks.

Yes, thanks Mike, you know really on the Viper side, the councils advised me to not be speaking too publicly about this step of our acquisitions. I can tell you in a general sense I have been really pleased with the amount of opportunities we've already had in the first 30-days and I think just look forward to providing more color on Viper in our upcoming calls. On this specifically again we laid out the benefits to Diamondback pretty clearly during our IPO on Viper and I think you can just refer back to our Viper webpage and you can see all of those details.

Okay that’s fair enough and then with Viper, is there desire to go outside of the Permian and look for deals and does that ultimately – bang is obviously very Midland focused talk about ramping to nine rigs there. Does that ultimately lead you to want to take Diamondback outside in the Permian as well?

You bet. Thanks Mike. Well specifically on Viper as we talked about during the IPO. I mean Viper is not constrained to the Midland basin, obviously Diamondback is laser focused on execution results in the Midland basin, but the Viper level we are looking for accretive deal in all of the other basin and the three kind of criteria we are looking for are basins are actively being developed, oil weighted basins and the operator that’s developing the minerals is a confident operators. So those are kind of the three broad focus items that we look at when we start screening deals for Viper.

Great thank you.

Thank you our next question if from Jason Wangler of Wunderlich. You may begin.

Good morning guys. Just curious as far as you talked a lot about just different infrastructure and bottlenecks, just curious on the frac side as you are seeing that one obviously you keep ramping the rig count, the plan is to ramp it further later this year this year and next. What are you seeing as far as frac and as far as the contracts that you may have now or what you may have to look at as you go forward?

Yes, we are continuing to see some cost pressures from the pressure pumping side of the business one of the things that’s we’re pleased with is that we’ve got two dedicated crews working for us right now. And, we’ve got roughly 40 or so wells to complete in the second half of this year and all those 40, roughly 30 of them will be on pads and you know the efficiencies that I talked about in my prepared remarks on the cost side a lot of that comes on a stimulation side, because you have just got – you set a crew right down the location and get two or three wells at one time and so. I'm still trying to do everything I can to hold the line of cost and offset any increases in costs with improved efficiencies, but I do think that the tension is getting pretty tight now. We’ve got two dedicated crews as I mentioned and we’re looking at maybe bringing a three dedicated crew on later this year, early in the first quarter. One other things that the stimulation companies have communicated to us is that they really like working for Diamondback Energy, because even though like right now we’re just running five rigs, it’s really equivalent to running – working for another company that’s running eight or nine of 10 rigs, because of how fast we get these wells drilled. So, it really builds a nice inventory of wells that they can just move to very quickly and that help efficiency on their side and it helps own our cost side as well.

That’s helpful. And then, maybe just on the other side of it, as you get the oil out I know that you are always focused on the take away, how are you seeing that market playing out, I think it was a little bit differential issues somewhat in the quarter at one point with the refinery down, but how are you seeing that market playing out so far?

We know that there is serve large pipelines that are ready to either start filling or we’ll hear shortly in the second half of this year that the differential blowout that occurred to couple of weeks ago and month ago will come back into more traditional trading levels on the Mid-Cush differential. We are continuing to look at space that’s available on these other pipelines that are leaving the Permian that are not going to Cushing, Oklahoma and just as a reminder we've got 8,000 barrels a day gross that we've already committed and are moving right now on the Magellan Longhorn pipeline and we received the LLS pricing for that. Pricing for that. So, any incremental barrels above 8,000 barrels a day have been subjected to that Mid-Cush differential, but at least we've got a little insurance for our stock holders on 8,000 barrels a day and we're looking to get more space on pipelines away from Cushing, Oklahoma to try to address that issue.

Great, I’ll turn it back. Thank you.

Thank you. Our next question is from Jeffrey Connolly with Mizuho Securities. You may begin.

Hi, guys. Thanks for taking the questions, you mentioned in the prepared remarks, production might be a little lumpy due to a lot of wells on pads. Can you give us any color on the completion schedule in the third and fourth quarter that might help us model production?

Yes, as I was just talking with Jason there I think we got 40 well that we've kind of scheduled between now and the end of the year and with two full dedicated crews right now, it ought to be in that 20ish wells per quarter. And again, you know, we've got to have a little flexibility in that. But in order to get our annual guidance of wells completed, we need knob that 20 wells per quarter and that’s where we've got laid out right now.

Travis thank enough helpful I will jump back in the queue that’s it from me.

Thanks Jeff.

Thank you. Our next question comes from Willis Fitzpatrick of Johnson Rice. You may begin.

Good morning. I know that you guys hit on this a little bit, but the majority of yours wells going forward should be on at least two well pads. Can you talk about any potential to accelerate or to make those three or even more wells per pad and then also the availability of walking rigs where you are?

Yes. I’ll answer those in reverse, the walk-in rigs, we try to have about half or three quarter of our rig fleet available that walk from well-to-well. For example that three well pad that we talked about down in Upton County that rig was set up with walk-in fee and it moved from well-to-well in less than eight hours. It typically takes us two and half days to move a rig and so on a three well pad we moved them in eight hours. And about a half to three quarters of our rig fleet will be set out to do that. We also because we still are geographically diverse, you know, we need to have these rigs that are quick to move a minimum number of loads and then can move from area-for-area and so I can't have all of my rig fleet that are set up with feet because I need those fast moving rigs. So out of the – and I’ll look to Mike here real quick, but out of the six rigs we'll have it at the end of this year Mike, how many of those will be set up with the rig feet.

You have four rigs with walk-in feet and you'll have two that are H and P rigs that are quick movers and rig release spud times, you're looking into 2.5 to 2.8 days to for the HMP rigs and a full pad with walking feet to move from pad-to-pad is about 3.5 days from one of the big 1500 horse rigs with the feet. And then as Travis mentioned between wells, it's about eight hours. Actually spud, rig release to spud will run you a little about 0.8 days or a pad when we can when we can walk the rig from one to the next.

Thank you, Mike.

Yes.

Perfect And then just one more sort of in the same vein, it seems like those cost savings per well were a little higher than expected, but should we think about that as generally shifting toward the lower end of the 9.6 to 7.4 complete the well cost range or should we think a bit it’s actually shifting that range?

Well, I wish that I could tell you that shifting to range lower what I think it may end up doing is offsetting some of the cost increases that we're seeing. So at this point I don't want to signal that we're going to be lowering the range on per well completions.

That’s perfect. Thank you so much.

Thank you. Our next question is from Joseph Reagor of ROTH Capital Partners. You may begin.

Good morning, guys. Most of my questions have been answered, but just one key point is with all the water supply issues that have been going on in many of the basins, how are you guys, planning ahead for this with the additions of up to three more rigs over the next 18-months?

Well, Joe, I talked a few minutes ago about our water usage plan for each area and a little bit more detail on that when it comes to access and accumulation that means it's the number of fresh water or Brackish water wells that we drilled in advance of the drilling rig arriving and it also means we’ve got the size appropriately our storage frac pits for these types of water. So, that’s what we are doing, we are on the newly acquired acreage, we are rapidly coming up with the water usage plans that gets all the way to how prolific the Brackish water wells are and how prolific the fresh water wells are and then what size frac pumps we need to accommodate our rig schedule. I think I had a previous question about increasing from two to three well pads and ideally we would like to stay with three well pads, but some of that hinges on our ability to accumulate water and also lateral link as well too. The longer laterals also require obviously more stimulation fluids. So it takes a little longer to accumulate that amount of stimulation fluid.

Okay. And do you guys have an idea of what kind of relative cost inflation impact the water supply situation has had on your guys over say the last 12-months?

Yes, I wouldn't say that the water supply has impacted the cost. What I would say is that it's more on the pressure pumping side, the hydraulic horsepower charges that we're seeing or working their way up. Really the only difference on the stimulation fluid is that when we drill these Brackish wells, they're a couple of $100,000 a piece as oppose to a fresh water well, which is $10,000 to $20,000a piece.

Okay, thank you.

Thank you. I would now like to turn the conference back over to Travis Stice for closing remarks.

Thank you. Thanks again to everyone participating in today’s call. If you have any question please reach out us using the contact information provided.

Ladies and gentlemen this concludes today’s conference. Thanks for your participation and have a wonderful day.