Adam Lawlis - Investor Relations Travis Stice - Chief Executive Officer Michael Hollis - Chief Operating Officer Teresa Dick - Senior Vice President and Chief Financial Officer Russell Pantermuehl - Vice President, Reservoir Engineering

Neal Dingmann - SunTrust John Nelson - Goldman Sachs Michael Glick - J.P. Morgan Gordon Douthat - Wells Fargo Kashy Harrison - Simmons & Company Jason Wangler - Wunderlich Tim Rezvan - Sterne, Agee Brian Downey - Nomura Securities Chris Stevens - KeyBanc Capital Markets Inc.

John Aschenbeck - Seaport Global

Thank you, Andrew. Good morning and welcome to Diamondback Energy and Viper Energy Partners joint first quarter 2016 conference call.

During our call today, we’ll reference an updated investor presentation, which can be found on our Diamondback's website. Representing Diamondback today are Travis Stice, CEO; Mike Hollis, COO; and Tracy Dick, CFO.

During this conference call, the participants may make certain forward-looking statements relating to the company’s financial condition, results of operations, plans, objectives, future performance, and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors.

Information concerning these factors can be found in the company’s filings with the SEC. In addition, we will make reference to certain non-GAAP measures.

The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I’ll now turn the call over to Travis Stice.

Thank you, Adam. Welcome, everyone, and thank you for listening to Diamondback and Viper Energy Partners’ first quarter 2016 conference call.

During the first quarter of 2016, commodity prices tested low as not seen in the past several years. As such in consistent with our strategy of capital discipline and maximizing stockholder returns, we slowed our 1Q completion activity and now have an inventory of nearly 30 drilled but uncompleted wells.

As a result of increased activity associated with running a third drilling rig longer than we initially anticipated and recently picking up an additional frac crew, we are raising the low end of our full year guidance to 34,000 Boes per day from 32,000 Boes per day. We anticipate some lumpiness in the second quarter projection with the response from completions associated with the second frac crew expected in the second half of this year.

Should crude prices continue to strengthen, we could pick up a fourth horizontal rig early in the third quarter. Alternatively, if prices soften from current levels, we could stay at three drilling rigs or less and again moderate pace of completions.

With over 230 million in cash and in undrawn credit facility, we’re well positioned to increase activity levels without stressing the balance sheet. When you compare our current financial position to nearly two year ago when oil price was at its peak, our balance sheet is now stronger, we have more liquidity and higher credit ratings and perhaps that we’ve been able to become even stronger financially during the past year.

Also we continue to lower well costs and operating expenses through efficiency gains, optimization and cost concessions. Our executing metrics continue to improve across the board even as we began development in new areas like Howard and Glasscock Counties.

All in cash cost for the quarter including LOE, G&A, transportation and production taxes are currently below $10 per barrel demonstrating how lean and efficient the Diamondback organization operates. We are pleased with the performance of our first five Glasscock County completions which are exceeding our expectations at the time of the acquisition.

This week, we intend to begin completion of wells in our new core area in Howard County where offset activity remains very encouraging. We expect to see more opportunities to grow our company and believe our prudent track record of execution and low cost operations makes us a natural consolidator within the Permian Basin, while we evaluate all deals in the Permian, we will only do transactions that we believe are accretive to our stockholders.

I’ll now turn the call over to Mike.

Thank you, Travis. Diamondback continues to post encouraging results to achieve company execution records.

Slide 7 shows that on average, our Glasscock County wells are tracking a 1 billion Boe type curve. Our Riley wells were completed using the higher sand concentration and early production time results for these wells are very encouraging.

Slide 8 shows peer activity in Howard County, but we will begin completing our first three well pad this week. As a reminder, we have drilled two pads that target the Lower Spraberry, Wolfcamp A and Wolfcamp B intervals.

Slide 10 shows that Diamondback continues to drill wells faster than offsetting peers in all our core operating areas. During the first quarter of 2016, we drilled a 9,800 foot lateral well in Howard County in less than 11 days from spud to td.

We also drilled a 7,300 foot lateral well in Spanish Trail in under ten days from spud to td. A new company record Midland County.

Lastly in April 2016, we drilled two wells the 10,000 foot laterals in Andrews County in 25 base from spud of the first well to rig release of the second. Slide 11 shows our current realized well cost reductions, which have come down roughly 35% since the peak in 2014 and approximately 5% quarter-over-quarter.

Leading edge drill complete and equip cost of trending below $5 million for 7,500 foot lateral well and between $6 million and $6.5 million for 10,000 foot lateral well. Slide 12 shows reductions to our current realized lease operating expenses since the peak in 2014.

We are extremely proud of our production organization for continuing to lower operating expenses. We’ve reduced LOE from over $8 a barrel in the first quarter of 2015 to $5.23 per Boe in the first quarter of 2016 due to reduced cost and further improving pumping practices.

As a result, we have lowered our LOE guidance to 5.50 to 6.50 per Boe from a prior range of $6 to $7 per Boe. With these comments now complete, I’ll turn the call over to Tracy.

Thank you, Mike. Diamondback’s first quarter 2016 adjusted net income was $2 million or $0.02 per diluted share.

Our consolidated adjusted EBITDA for the quarter was $60 million. Our first quarter 2016 average realized price per Boe including edges was approximately $27.

During the quarter, our cash G&A cost were $1.33 per Boe, while non-cash G&A was $2.39. During the quarter, our capital spend for drilling, completing and equipping wells was 76 million.

Our infrastructure costs were 5 million and we paid 4 million on our non-operated properties. A portion of first quarter less related to fourth quarter of 2015 activity, we spent an additional 90 million on acquisition during the first quarter of 2016.

Diamondback’s [Technical Difficulty] as a company that has a stronger balance sheet, more liquidity and higher [Technical Difficulty]. At the end of March 2016, we were undrawn on our secured revolving credit facility.

With over 230 million in cash and 500 million in undrawn revolver capacity, we have ample liquidity to fund our budgeted 2016 drilling program. Our net debt to annualize first 2016 EBITDA is 1.1 times as shows on Slide 13.

Our practice of limiting our commitment to a portion of our borrowing base again reflects our track record of financial discipline. Moving to Slide 14, we provide our guidance for 2016.

As announced last night, we increased our 2016 production guidance for a range of 34,000 to 38,000 Boe per day. As a result of picking up the second dedicated completion crew, we now expect to complete a range of 35 to 70 growth wells.

We have also lowered our 2016 ROE guidance range to 5.50 to 6.50 per Boe from a prior range of $6 to $7. I’ll now turn to Viper Energy Partners, which announced a cash distribution last night of $14.09 per unit for the first quarter.

Viper has no minimum quarterly distributions or complex ownership hierarchy. The majority of cash flow is returned to unit holders through quarterly distribution providing upside when oil prices rebound.

Spanish Trials is one of the most economic areas in Permian Basin and we expect the operators will complete the backlog of over 20 DUCs and continued strength in oil prices. At the end of first quarter 2015, Viper had 43 million drawn on its revolver.

I’ll now turn the call back over to Travis for his closing remarks.

Thank you, Tracy. Diamondback again delivered a strong quarterly [Technical Difficulty] reduce cost and expenses, improve execution and demonstrate capital flexibility in response to commodity prices.

We’ve gotten stronger financially and our poised to accelerate into oil price recovery. We are pleased with the early well results in Glasscock County and continued to be optimistic about Howard County potential.

We look forward to sharing our initial Howard County results in the upcoming quarters. Operator, please open the line for questions.

Good morning, everyone, nice quarter again. Hey, Travis for you and the guys here, just how do you think about when you these days on optimal well either in Howard, Glasscock or obviously Spanish Trail in relation to sand per foot lateral link, I guess kind of lot of people are obviously throwing a lot more sand in it, I am just wondering maybe in those particular things, how you think about, let’s just stick with lateral link and amount of sand you look at it?

Sure. The lateral link question is a little easier.

I think it’s also more well understood. You know longer is certain better.

In fact couple of months Diamondback is going to be drilling our first 13,000 foot lateral. You know on sand per foot, you know we continue to test and follow the industry in putting more sand per foot.

Our current average is running around 1,600 pounds per foot. We got some test that are coming up that will test even higher sand loadings.

But in a general sense, we believe that you know the rest, if they has an efficient frontier of just a - the right amount of sand. And well we don’t know exactly what the answer is.

We know somewhere we believe in that 1,600 to 2,000 pounds per foot.

Okay. And then just one if I could, how do you think about in either kind of the again the three areas just an optimal number of wells per pad.

I mean does that just vary sort of pad per pad depending on exactly how configures the acreage. You know what do you think about, is it a three well, four well or can you - will you start to even accelerate that as conditions improve?

Yeah, so Neal, I believe you know if we are just looking for planning purposes probably three wells, three stack wells per pad and then we’ll move across depending on the density and where we started the wells somewhere between six and eight wells across the section. Certainly we’re very comfortable with three or more zones in Glasscock and Howard County.

And as we’ve seen in Midland County and some of the areas, we’ve got potential for the Middle Spraberry and Lower Spraberry as well.

Alright, thank you.

Good morning and congratulations on the quarter. When I look at your slides, you guys put rig ranges of two to three for $30 to $45 a barrel and $45 to $55 per barrel.

You mentioned in your remarks you could add back a rig in early 3Q. I am just curious, is this a function of seeing continued improvement from well economics or is this just a view that oil prices will continue more higher?

Yes, John it’s actually both but I think you know the reason we level that range out there is because we want to be able to respond when we strengthening our oil prices. You know we’ve got 45 to 55, we’ll say everyone three to four rigs.

Our rate returns for all these wells particularly in the Midland County ranging somewhere between 50% and 100% rate return. So we’ve got a lot of opportunities to drill extremely high rate of return wells.

So we’re now looking for economic improvements and we’re looking for you well cost being down from where they are now, they help make the decision. We’re really focused on the macro conditions on our oil market and then the near term price forecast to make those decision.

But again consistent with what we’ve always done and said when return to our investors are going up, we accelerate into that environment.

That’s helpful. And then just, can you remind us on the fourth rig, would that be reactivating rig under contract or would you guys be actually contracting a new rig and if the later, you know what sort of term would you be looking to look up potentially?

John, it would be a reactivation of well - rig we currently have stacked on one of our locations.

Okay. And then I had just one high level question if I could.

When you think about acquisitions, do you look it’s hard at Delaware Basin or do you think that maybe Diamondback doesn’t currently have sufficient scale or the well would be inferior that you don’t want to stay continued focus on the Midland Basin?

We continue to look at numerous opportunities in Delaware Basin. What I talk to my business development group about is you know as we look at different opportunities, all we upgrading our portfolio.

In other words we said simple is the average well and the new opportunity at or above the midpoint of the well in our current portfolio. And if it’s not, it’s like a dilution to our inventory.

And at this point those trades are hard for us to do. But we are certainly continue to look you know everywhere in the Midland Basin but also in the Delaware.

Is there a certain scale you think you need to be to more into the Delaware or is it simply those assets are above the average the portfolio you could build on even in smaller levels?

Yeah, we - it really gets back to the economics of the decision. You know at what price and what returns do we think we can generate our shareholder and then you know secondary rate down the line is what size is it.

That’s very, very helpful. I’ll let somebody else jump on.

Thanks John.

Good morning.

Good morning, Mike.

Several operators are testing multiple downspacing concepts in Lower Spraberry and northern acreage, could you speak to your view on how well density ultimately plays out in that zone? And then also, do you see the potential for multiple benches move into your northern acreage?

You know Mike, we believe the testing that’s going in Spraberry right now is appropriate. We’re testing downspacing as well as maintain to be fast followers on that.

I think you have to be careful in downspacing based on our industry’s experience over capitalizing a section. That being said though, we’ve got to put the drill bit tighter and in more laterals to come up with that ultimate final answer.

And we’re doing it, other operators are doing it as well and it’s sort of one of those stories that is going to evolving. We tend to be a little bit more cautious but certainly as well densities increase and additional stack pays or tested that rising cordless all the ships are in the basin.

And in from a higher level, you guys continue to improve on both the efficiency and productivity side, maybe could you speak to kind of what different from Diamondback’s perspective on both fronts?

You know I think the remarkable thing about the Permian Basin, I think we’re in a 95th year since our discovery well is that we’re almost a basin that’s perpetually in the third to fourth and that’s because there is just so much hydrocarbons in the strat column that you know things like technology improvements, horizontal drilling, fracking technologies, all of those things perpetually bring you back in the third to fourth. You know as I see you today and look at our costs and out execution you know all I look at our operations organization, I say, can you give me more.

I mean we’re - it feels like unless there is a substantial technological breakthrough that we’re getting close to the bottom end cost and close to the maximum in efficiency. But that doesn’t mean from Diamondback’s perspective, we will continue to pull, couple of years ago, we are probably saving you know quarters and dimes, you know right now we are picking up pennies.

And every little bit matters. And it’s just a remarkable basin to be developing the Permian is with all the well that’s in place.

And then last one from me, I mean could you just speak to the service industry’s capacity to respond to acceleration activity in Midland Basin?

You know Mike, I think you know obviously the cause that the public service guys are making their best equipped to respond to that. You know I think if the industry was to all of a sudden mash the accelerator completed to the four and standup a 100 drilling rigs in the Permian Basin, you know we would have a hard time I would believe on the pressure pumping side immediately responding to that.

But if we do a prudent build into a new norm of drilling rig and they will run in more or less than a 130 rigs out here in the Permian right now and that’s down from 560 just a few years ago. If we build into that environment, I believe our service - the service sector, our business partners can appropriately build their organizations backup to respond to the operators’ needs.

That certainly the conversation I have with my business partners at Diamondback.

I appreciate the color. Thank you.

Yeah, thanks, good morning, everybody. Somewhat related question.

On the completion side well, going back to your presentation, I guess you indicated some pretty good efficiency on the drilling side I should say. And I was just trying to get a sense on the completions, how much are the completions impacted by efficiency gains and to what extend are those sustainable in an upturn where industry is adding rigs and drilling more wells?

You know probably a little bit different than what we see on the drilling side. You know the majority the cost that are associated with the completion or tied up with the pressure pumping.

And the pressure guys you know as commodity prices you know call for increased activity, they are going to have to go and repair their balance sheets. And so I anticipate costs you know increasing at some point in the future probably not in the next quarter or so, but some point in the future.

And as such most of that will transfer right back to the operators. So we do things on the completion side and make our completions more efficient absolutely we are.

But I would say to a larger degree on the pressure pumping side, we are relying on their business partners to provide you know fair prices and good services.

Okay, it makes sense. And then another question I had was just giving the results in Glasscock were pretty solid, how do they compare to initial expectations and then given the one million barrel a day type curve give or take, how do that - how do those wells compete within the portfolio now?

Well certainly the wells are in the top quartile of our portfolio at least certainly in the Wolfcamp A, we’ve been extremely pleased with the Wolfcamp A and it’s competing now with, you know almost competing with some other wells in Midland County, some of little favorite wells in Midland County, the Lower Spraberry that we tested which was the lot of points in this portion of Glasscock County and the Lower Spraberry and as I reported in my call, we’re really pleasantly surprised. I think we’ve released an IP 30 rate in our investor presentation right now that continues to involve.

So I think about 1,125 Boes a day for an IP30. So again that was a very strong Lower Spraberry well not in the top quartile of our portfolio as well.

So both the Wolfcamp A and Lower Spraberry are well above our expectations at the acquisition time. The Wolfcamp B is about in lined with our expectation, so two out of three is significantly above our expectations, so on average it makes the whole strat column look better.

Okay and you put these on ESP?

Yeah, what we’ve decided to do up early on in our development scenario is, as we move into areas which we feel have strategic significant to us. That we want to try to eliminate is many variables as we can and whether it’s in Glasscock County or Howard County, the initial wells that we put in there, you know we also put on ESP that way that allows us to compare ESP performance in the way that the bottom pressure declines overtime to wells that we do have a good control like in Midland County.

So we believe that that’s the best way to do initially. Their application for gas lift absolutely be, you probably save maybe as much as $100,000 to $150,000 per well.

But they do have a little bit more operational uncertainties within as oppose to an ESP. And just one other point on the ESP that my operations guys continue to remind me is that as we move into areas where we have a dense spacing of horizontal wells and we frack and we put frack water in the offset wells, it’s a whole lot easier to go back out there and turn the release that’s speed up the sub-pumps and pull the water out of the section.

And so overall this whole section you know starts producing oil sooner than it did, sooner that it would have had those wells on gas lift. So there is an economic offset, positive offset to the increased our front cost.

Alright, I appreciate the color. Thanks.

Hi, good morning. Thanks for taking my questions.

Excellent work on just bringing down cost on quarter-over-quarter basis with walkouts now below $5 million, I was wondering if you could just provide some color on some of the drivers of the cost reductions relative to what you present in last quarter? And then just thinking about of recovering the commodity environment you know how much of this cost - how much of this savings you think are sustainable, so for example for the 7,500 for lateral wells, if they cost $5 million today in a $50 to $60 environment, what do you think that moves up to you?

Kashy, this is Michael Hollis. I’ll try to answer both of those for you.

On the cost front, a lot of the savings are coming from some of the optimizations on the drilling side as well as some pricing that we’re getting on the pressure pumping side. We’re seeing about quarter-over-quarter about 5% reductions in cost of goods and services, pipe, steel, iron that we buy and use in the wells.

But as far as the drilling side, it’s typically speed with which we drill modified case and designs, we’re running shallow well casings. And then on the pressure pumping side, its current pricing that we’re getting from the industry right now.

As far as stickiness of this current price environment, as we all get back to work in the next few quarters, until the iron gets utilized out of the yard, I think we’ll continue to see these lower prices stick around for a while. But as the other basins tend to pick up orders and whether its $50-$60 oil and the Eagle Ford and the Bakken start getting to work.

We’ll start seeing these guys have to raise their prices because it have a lot more competition for the yard.

Thanks for the color there. And on the operating expense side of things, in one of the slides, you highlighted that 9% of oil productions is going to be on pipe by the end of the year and 80% of the water will be piped salt water disposal.

Could you maybe just share some color on what LOE may look like by the end of this year on a per barrel basis?

The oil pipeline that’s more of our realized prices that we see, the water side again every time we come into a new area that’s one of the first things we do is building at the structure out for both supply and removal fluids from the wells. So as we go forward, again a lot of its going to depend on the volume forecast and what oil prices do.

But if we keep fairly flat oil price, it would be fair to say that we should have fairly flat LOE for what we have in our guidance. If oil prices pull back and we pull back the activity and migrate to the midpoint of our production range, you’ll see those LOE cost go up slightly.

Got it. And just shifting gears to Viper, I was just wondering if the - could you share some light on the current A&D market in the mineral space, if there is any color you can share there?

Yeah, and we don’t typically like to talk about acquisitions that we under current evaluation. But I can just say in a general sense that the deal flow on the Viper side has moved up materially you know late last year and through the first quarter of this year.

So Viper is fully engaged and trying to deliver some accretive deals to over.

Okay, well thanks for the color there and thanks for taking my questions. I really appreciate it.

Thank you.

Hey, good morning, guys. Mike you may have touched on it a bit there, but was just curious the Slide 10 that shows obviously the really solid days of drilling.

It seems to me at least that as you look at those graphs specifically Howard and Glasscock, the first call it 8,000 feet basically the vertical portion of that well really gets down a lot quicker than all the peers. I think you mentioned the modified casing in the previous answer, but just curious if there is something operationally different that you guys are seeing for better word gives you guys a really good head start in getting these wells down quicker?

In general the modified casing is more on the Western side of the basin. We’re very hurdling into Howard and Glasscock.

So we’ll continue to push the envelop there. So you are not getting that benefit yet in those areas.

What you are seeing here is just blocking and tackling that we do every day, it’s good research in the area and it’s just good drilling practices that we try to employ, which I could say there were secret thoughts to being able to deliver that kind of performance but it’s essentially just good hard work from the guys in the field.

Okay, I appreciate it. And then just maybe for Tracy just on the tax side, just kind of cleaning up some numbers, obviously there wasn’t any effective tax rate this quarter, is the thought process going forward maybe just for modeling purposes what we should be looking at?

Yeah, I would suggest that we - internally I am modeling no tax for the remainder of the this year. This is a result of the impairments we have been booking over the last few quarters as tried to start Q flat now over the last really willing 12 months, we could get back into our tax position but I don’t foresee that and tell probably ‘17.

Okay, I appreciate it. Thank you very much.

Hi, good morning, folks. Thanks for taking my question.

I was hoping to change gears a bit and ask about differentials. If you look at both Diamondback and Viper, we’ve seen kind of some volatility, you know cause all hydrocarbons.

I know that Viper as other operators kind of producing some of its barrels. But can you kind of explain what that variability was and maybe give us a thought on what we can expect the rest of the year?

You know Tim, I am not sure that we’ve specifically study that specific question. I can tell you that we’ve got guidance soon there both at the Viper level and Diamondback level that that would anticipate kind of what you’ve seen is more consistent work we see going forward.

Okay, so it’s nothing on the NGL sort of processing side of regarding assay into drive kind of realizations for the first quarter?

Yeah, I mean there is - you know there is a couple of things, I mean one is you know the amount of that thing that is affect that. The other thing is prices get lower, you’ve got fixed T&S fees, so you know as prices get lower make sure your differential look bigger.

So hopefully we’ve got some price improvement on the NGL side that differential going on as well.

Okay, that’s fair. Just you know you saw $0.35 deterioration and from 4Q to 1Q in gas for FANG and kind of similar move down for Viper, that’s all.

Okay, I’ll leave it there. Thanks.

Great, nice quarter, guys. Thanks for taking my question.

Just quick one, given that first quarter production came it at the high end of the full year guidance, can you just give us a sense of how we should think about the general production trajectory towards the rest of the year? I know you’d mentioned the lumpy second quarter, but just curious is to how we should think about the moving parts as we head into the back half of the year?

Sure. I think as Adam explains it, when we talk about it internally, we look at our production more in a J-shape recovery with most of the completions as I outlined with the second frac crew impacting you know 3Q and 4Q.

That being said thought we have to be a little careful on you know thinking what we are going to do quarter-over-quarter because we don’t guide to the quarter. And one of the reasons is because we can move into the quarter or out of a quarter of three or four wells stat to pay all logistics and then how quickly we can get to that.

And it would bring one into the quarter you know and there are three of four well badge brining 3,000 or 4,000 barrels a day, you can have material impact on the quarter. So again while we stick towards an annual guide is because of that somewhat difficulty in forecasting when these stacked pads come on.

Great and if I think about the potential for fourth rig as you mentioned, so I think about of that’s 3Q event that probably might get a little bit in the fourth quarter but that’s more effecting 2017 type volumes?

Yeah that be building into recovering oil price commodity type and more late this year maybe exit volumes were primarily 2017.

Great, thank you.

Hey, good morning, guys. Travis, maybe I could just touch on the Delaware base in M&A again, have you see acreage there that you think would be accretive to your average inventory quality?

And if so I guess it more a question of valuation at this point or do you think the Delaware just doesn’t really compete with what you have on the Midland Basin side?

You know there is portion of the Delaware that we believe you know we believe in complete. And I am not saying that where necessarily the trades are occurring.

You know in a general sense, you know we just continue to look at the Delaware from Northern Delaware to Southern Delaware and we’ve valuated relative to what’s currently in our portfolio and try to make good decisions based on that that is going to be accretive to our shareholders. So probably more valuation point.

Okay, got it. And I guess what are the expectations on Howard County at this point, I mean what you have in Spanish Trial and now Glasscock both were pretty tremendous.

I mean should we - I guess what you guys think in terms of how Howard County is going to set into the packing order at this point?

Well, we update - which slide that is - we update in our slide decks and new data point slip up in Howard County on Slide 8 and I made the comment when we acquired this asset about this time last year that this was the most de-risked acquisition down back at April-May. So as you peruse the date that’s on Slide 8, you can see well we continue to be in on the results from the wells and we’re going to be pumping sand down in the few days and we’ll have what we believe are some good tests in our October call, we’ll at least have 30 day rate on our first three well pad and probably some early indications from our second three well pad.

But if you just look into data over there, it looks pretty strong.

Got it, thanks a lot.

Good morning. Thanks for taking my question.

Just had a follow-up on extended laterals, two part question really and that is, what percentage of your acreage what you estimate ballpark figure is currently longer lateral, let’s call that 10,000 foot plus? And then secondly, how many 2016 35 to 70 completions again ballpark figure what you estimate around that 10,000 foot plus range?

I’ll let Russell answer that question.

Yeah, I mean it obviously varies by area but I think probably we’d say about 70% over our acreage, we can drill 10,000 foot laterals and probably for the wells will drill and complete this year. I think that number is in the 60% to 65% range.

You know what’s happened is you know been successful in trading acreage and pulling acreage to dill longer laterals because not just as the rest of the industry wants to. So like our Glasscock acreage is probably you know net 70%, 10,000 foot laterals and Howard may end up being up a little higher than that.

Perfect, very helpful, thanks guys.

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