Adam Lawlis - Investor Relations Travis Stice - CEO Tracy Dick - CFO Russell Pantermuehl - VP Reservoir Engineering

Dave Kistler - Simmons & Company David Amoss - IBERIA Capital Partners Neal Dingmann - SunTrust Mike Kelly - Global Hunter Securities Jason Wangler - Wunderlich Gordon Douthat - Wells Fargo Gail Nicholson - KLR Group Tim Rezvan - Sterne, Agee Jeff Grampp - Northland Capital Markets Michael Hall - Heikkinen Energy Advisors

Thank you. Good morning and welcome to Diamondback Energy and Viper Energy Partners joint second quarter 2015 conference call.

During our call today, we’ll reference an updated investor presentation, which can be found on Diamondback’s website. Representing Diamondback today are Travis Stice, CEO; and Tracy Dick, CFO, as well as other members of our executive team.

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 and 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’s and Viper Energy Partners’ second quarter 2015 conference call.

Before we begin, I would like to congratulate Mike Hollis on his promotion to Chief Operating Officer. As most of you know, Mike has been our Vice President of Drilling since September of 2011 and has been invaluable to our organization.

As you’re aware, commodity prices in the past 12 months have been volatile, decreasing over 50%. Our strategy has remained unchanged since before our IPO.

We focus on stockholder returns, best in class execution, low-cost operations and our conservative balance sheet that allows us to succeed in the current environment. The position Diamondback is in today is not just a result of our recent response to falling commodity prices but rather a reflection of the decisions we made over three years ago as we were building the company.

When I started my career in 1985, oil price was in a freefall and oil was mostly below $20 a barrel for the next 15 years. Sound companies survived and some prospered.

Those that prospered were the efficient, low-cost operators with good balance sheets and low debt. These companies also took advantage of the times and added Tier 1 core acreage to their inventory.

That should sound familiar because that is exactly what Diamondback has done over the last three years. I fully expect that we will continue to prosper.

Our business model is simply to convert resources to cash flow more efficiently than anyone else. Our remaining locations for the year are expected to generate in excess of a 40% rate of return at a flat oil price of $50 a barrel.

This is why we resumed production growth and we will continue to grow as long as we provide attractive returns to our stockholders. We will continue to monitor the macro outlook and have the flexibility to adjust our program by responding prudently to market conditions.

Additionally, most of our acreage is held by production, providing further flexibility in 2016. Our balance sheet, cash flow, and ample liquidity can support our reacceleration.

We have additional non-debt, non-dilutive liquidity in our 88% ownership stake in Viper. As a result of decreases in cycle times from drilling optimization, completing additional wells, and the continued strength of our Lower Spraberry program, we are increasing production guidance for the second time this year to 30,000 BOE/D to 32,000 BOE/D from 29,000 BOE/D to 31,000 BOE/D previously, and plan to drill five more gross horizontal wells at the midpoint.

As announced last quarter, we have closed on approximately 12,000 core acres in the heart of the Northern Midland Basin that we are excited to begin drilling later this year or early next year. Our track record of capital discipline and accretive acquisitions has enabled us to add acreage into the top quartile of our portfolio.

I will now turn to our updated slide deck that can be found on our website. Slide six shows our current cost savings for drilling and completing a 7,500-foot lateral.

We have captured 20% to 30% in cost savings due to cost concessions and permanent efficiency gains. We still expect our average D&C costs for the year to be within the $6.2 million to $6.7 million range for 7,500-foot lateral.

This slide also shows our LOE cost savings. As our operations team has implemented best practices on the acreage acquired in 2014, LOE per BOE has decreased nearly 25% from the fourth quarter of 2014.

We still anticipate averaging between $7 and $8 per barrel for the year. Slide seven shows that the returns on our current Spanish Trail Lower Spraberry wells are strong, even at today’s oil prices.

When you include the effect of Viper ownership and assume a $6 million well cost, Spanish Trail Lower Spraberry wells are able to generate nearly a 70% rate of return at a flat WTI price of $40 a barrel. The two rigs added to our program will be primarily drilling in our new Howard and Glasscock positions where we also expect robust economics.

We are encouraged by the three tests of increased sand concentration in Spanish Trail. On average, we pumped about 1,900 pounds per foot on these wells compared to 1,300 pounds per foot in our standard completion design.

These three wells in Spanish Trail are outperforming offset completions by an average of 15% to 20% for a similar increase in cost. We will closely monitor these results and will adjust our program accordingly.

We plan to conduct further enhanced completions going forward. As a reminder, we decreased drilling and completion activity in the second quarter, primarily to realign service costs with depressed commodity prices.

Slide 11 demonstrates how production last quarter decreased as fewer completions were placed on production. Diamondback’s track record for peer-leading efficiency and execution continues, resulting in cheaper wells and driving differential returns for our stockholders.

Slide 13 shows that, on average, we drill wells significantly more efficiently than offset operators in Midland, Martin, and Andrews counties. Turning briefly to Viper, production for the quarter was up 99% compared to production in Q2 2014.

We are actively seeking accretive acquisitions for Viper that meet our criteria for packages in oil-weighted basins under active development by competent operators. You have often heard me speak about Diamondback’s commitment to delivering best-in-class operations and the highest cash margins in the Permian Basin.

Now more than ever, it’s apparent that our focus on capital discipline and stockholder returns has enabled us to be very opportunistic during this downcycle. In fact, either way you look at it, Diamondback is positioned to succeed.

When oil rebounds, we can quickly reaccelerate development of our core acreage. On the other hand, if commodity price remains depressed for prolonged periods, our strong balance sheet and track record for capital discipline put us in the position to acquire and consolidate assets accretive to our stockholders.

With these comments now complete, I will turn the call over to Tracy.

Thank you, Travis. Diamondback’s adjusted net income was $25 million or $0.41 per diluted share.

Diamondback’s adjusted EBITDA for the quarter was $110 million, which is up 6% from $103 million in the second quarter 2014. Our second quarter average realized price per BOE including the effect of hedges was $52.93.

Our lease operating expenses were $7.51 per BOE, an 8% reduction from the first quarter of 2015 and a nearly 25% decrease from the high in Q4 of 2014. We continue to seek cost concessions and to implement best practices on acquired acreage.

Our cash general and administrative costs were $1.24 per BOE, while our non-cash G&A costs were $1.58 per BOE, both within full-year guidance ranges. We believe that our total G&A of $2.82 per BOE is among the lowest in the Permian Basin.

We have revised our DD&A guidance for 2015 to a range of $19 to $21 per BOE from our prior guidance range of $20 to $22 per BOE. This is a result of the impairment charge we recorded this quarter.

We spent approximately $86 million for drilling completion and infrastructure and approximately $433 million for acquisitions. When you exclude the capital spent on acquisitions, we achieved positive free cash flow for the first time in our history.

We continue to expect our total capital spend to be in the range of $400 million to $450 million for 2015, unchanged from previous guidance due to cost savings and efficiency improvements. However, we do expect we will be near the upper end of this range as we have increased our gross completion guidance to 60 to 70 from the prior range of 55 to 65.

I’ll now turn briefly to Viper Energy Partners, which recently announced a cash distribution of $0.22 per unit for the second quarter. This represents an approximate 6% yield when annualized based on the July 28 closing price.

This is an increase of 16% from the $0.19 distribution declared in the first quarter. In the past year, Viper has paid $0.91 per unit to its unit holders.

During the quarter, cash available for distribution was approximately $18 million. Viper has no debt and an undrawn revolver of $175 million as of June 30, 2015.

In early July of 2015, Viper completed the purchase of an approximate 1.5% average overriding royalty interest on certain of Diamondback’s acreage, primarily located in Howard County, for $31 million. Turning to Viper’s guidance, we expect 2015 volumes in the range of 4,800 BOE per day to 5,100 BOE per day, up from the prior range of 4,600 BOE per day to 5,000 BOE per day.

As a reminder, Viper does not incur lease operating expenses or capital expenditures. I’ll now turn the call back over to Travis for his closing remarks.

Thank you, Tracy. To summarize, our prior decisions have positioned Diamondback to succeed in these market conditions.

We’ve preserved optionality either to increase activity levels or to spend within cash flow. Our wells are still highly economic, even at current oil prices.

We have minimal drilling obligations, with most of our acreage held by production. And we continue to execute on the things we can control.

We are excited to get to work in Glasscock and Howard Counties and we look forward to updating you on our progress. Before we turn the call over to Q&A, I would like to welcome our new employees to Diamondback and to thank everyone for what they have accomplished during the first half of this year.

On behalf of the board and employees of Diamondback and Viper, I would like to thank you for your participation today. Operator, please open the line for questions.

Travis, just a follow up on a comment you made with respect to the strength of the balance sheet and the prospect for consolidation. Can you talk a little bit, given the history of the acquisitive nature of Diamondback, a little bit about where you see the M&A market?

Similar to how we saw recalibration of service costs with lower commodity prices, should we see recalibration of M&A targets? And obviously, Diamondback, you guys are a premium currency out there.

Just trying to think through how you look at the next three months, six months, 12 months.

Dave, that’s a good question. My track record has always been not to talk about any specific deals we have going on, but it’s also reasonable that every trade that occurs in the Permian Basin, Diamondback shareholders should expect that our fingerprints are all over them.

With that being said, though, I think with the macro conditions that are going on globally right now and obviously the commodity price continuing to fall, I would think that would put somewhat of a dampening effect on the expectations of sellers. However, that didn’t necessarily happen as much in the first quarter of this year but I would expect somewhat of a softening of the expectations from sellers as they go forward.

Additionally, I think there’s potentially going to be some more distressed assets that may be coming on the market late this year or early next year if we stay in a period of prolonged commodity prices. So I think there’s going to be some opportunities for Diamondback shareholders.

We’re just going to have to wait and see how it all plays out and we get some solutions around some of the macro issues that I referenced.

Okay. I appreciate that.

And then maybe also extend that over to Viper a little bit. With mineral interests and the pull-back in the commodity price and corresponding cash flow to those that hold mineral interests, does that actually open up that environment for an opportunity to find more potentially acquisitive transactions on the royalty front?

Well, if you go back to just the timeframe right after IPO, crude was in a pretty good decline right after Viper IPO-ed. And I think our experience shows that it’s difficult to convince sellers to convert their ownership into Viper units when commodity price is still going down.

I think you need a little bit of stability in the commodity price before you get increased interest from sellers or from guys that want to trade their interests for Viper units. But that being said though, our pipeline’s still pretty full right now and we’re pleased at the progress we’ve made in terms of furthering these deals along.

We’ve not closed any and none have traded away from us either. So I think the market is a little bit in flux right now and so we’re just going to kind of have to see, say, over the next several months whether or not we can be do an accretive deal for our Viper shareholders.

Appreciate that. And one last one, just in the press release, you highlighted some of the positive downspacing results that you’ve seen so far.

Can you talk a little bit about the length of time you need to see those wells produced before you can have confidence with officially highlighting potentially more inventory across your portfolio?

Hi, Yes. This is Russell.

If you go to our slides deck, on slide eight we’ve changed it up a little bit on how we show that result. So we show, on average, for our 500 foot spaced wells versus our 660 foot spaced wells and our other singular wells that don’t have any offsets, and to date, you really don’t see any material difference.

So the early results are encouraging but we really need more time and more data. The 500 foot spaced wells that we have right now are essentially two-well pads, so you don’t have the full offsetting wells.

We are continuing to drill 500 foot spaced wells in Spanish Trail and by the end of the year, we’ll have a full half-section developed with five wells. So once we get those results, I think we’ll have a more definitive answer, but we’re certainly encouraged by the results so far, where we’ve got almost six months of data on the first 500 foot spaced wells that still look very good.

Great. I appreciate that very much.

Thanks for the added color, guys.

Thanks, Dave.

Travis, just trying to wrap my hands around potential scenarios in 2016. So two specific questions.

First, can you kind of point us in the direction of your inflection points on the commodity and what it might mean in terms of activity levels, say, a $40 case and a $60 case? And then kind of same question on well costs.

I know you said that your average well cost will be in your $6.2 million to $6.7 million guidance, but the leading edge is on the lower end of that range. So kind of update us on where you are and where you might go considering what’s going on with OFS with the commodity going down recently.

Certainly, Dave. I’ll answer those in reverse there.

Our current well costs are below $6 million for a 7,500-foot well, and we kind of felt like that was going to be the bottom of well cost, but now oil has taken another leg down and I think it’s reasonable to expect the service sector will respond with another stepdown in cost as well, too. What that’ll be and when that will occur I’m not exactly sure.

But I know if activity’s going to continue, there’s got to be another recalibration that falls in that $40 to $45 range. Again, you asked some specific questions on 2016.

David, there’s so much flux in the market right now, not only with the macro issues that we talked about with the previous question that I’m just not ready to talk specifically about 2016 looks like. What I’ve tried to communicate is that we focused on returns to our shareholders and to the extent we can still generate returns to our shareholders, we’ll keep some level of activity in 2016.

To the extent things haven’t recalibrated, we’ll show that same behavior we did earlier this year and we’ll slow down our capital spending and we’ll return to somewhere within cash flow or close to cash flow. So, I know that all of the questions on the call and you’re curious about how to model 2016.

The reality is we’ve got to get some stability in the marketplace before Diamondback’s going to come out with a very prescriptive view of 2016.

Okay, thanks. And then one quick follow-up: you guys have made great efficiency gains so far this year.

Can you just kind of give us an order of magnitude in terms of what we can expect over the next 12 months?

Well, I already mentioned that if commodity price stays low, we think there’ll be another 5% to 10% of cost concessions that will be offered up by the service sector. In terms of efficiency gains, we’re probably somewhere around 30% or so right now of total cost concessions.

And of that 30%, probably 10% or so is what we’re going to call permanent savings. And we’re looking to increase that number even further.

That’s not a new thing for us. We’ve been doing that all along, which is one of the reasons our execution performance is what it is.

But we think there’s still some more pennies to pick up and we intend to pick them up and pass them back on to our shareholders.

Travis, I saw just not too long ago this morning, I see Exxon’s picked up looks like another 40,000 acres, says here, in the core Midland. I guess two questions around that.

One, you can seem to see -- I guess when you look at competition to find acreage either near or around you, how do you view it today versus let’s say even a year ago when we were in a higher commodity market?

Well certainly, Neal, where Diamondback’s almost 85,000 acres sit, most of that is in what the industry is defining as perhaps the most lucrative investment shale horizon in the U.S. And that viewpoint hasn’t done anything but got stronger over the last 12 months, as Diamondback and other operators continue to post really impressive well results and cost performance on these wells.

So I would say even in a backdrop of declining commodity prices, this rock continues to impress to the positive, and that just means that that makes the demand for that rock that’s pretty tightly held even higher. And when demand is high for this kind of rock, it usually means prices stay high as well.

And, Travis, I guess on this one it shows they did an acquisition and a farm-in. I guess, are you open to any sort of type of acquisition?

Yes, again, specifically we don’t talk about acquisitions. But in a general sense, drill-to-earn where we can provide another operator our execution excellence, I think that’s a meaningful way to move into acreage.

So, yes, we’ve considered and offered numerous drill-to-earn type of opportunities.

Thanks. Travis, you mentioned that Diamondback will continue to grow as long as you’re seeing strong returns.

And I’d just like to get your thoughts around that and how you think about what qualifies as a strong return. I think you mentioned 40% project IRRs for the rest of this year.

What’s your limit on that where you want to back off? And then on the other side of that, talking about potentially going up to eight rigs next year, what you need to see to step on the gas and maybe accelerate the rig count, just from that returns perspective?

Thanks.

Yes, Mike, I did mention that the remaining wells we have to drill this year are all somewhere between 40% and 50% rate of return and it’s hard to argue with that kind of returns to not continue to deliver that to my shareholders. So if we stayed at being able to generate rates of returns that robust, I think you’d look for us to continue to stay at either the level we’re at right now and maybe even a slight increase.

To get to the seven rigs, eight rigs, nine rigs, we’ve got to have another recalibration of service cost and commodity price. And I’m not sure exactly what oil price that translates to, but that’s how we’re looking at the world right now, Mike.

Okay. Appreciate that.

And let me just ask you on the efficiency front, if you could talk about cycle times now just spud to TD where they are now or where do you expect to be going into 2016 versus maybe where it was as you entered 2015? Just talk about the overall improvements you’ve seen there.

Yes, we’re currently using for our planning purposes about 18 wells per year per rig. We were using about 12 wells per rig last year and we’re now about 18 wells per rig.

And we’ve got actually designs on as many as two wells a month per horizontal rig for a 7,500-foot lateral. So we’re continuing to push the envelope and that’s where we’re at right now, Mike.

Okay. Appreciate that.

And congrats to Hollis, university [ph] on the promotion there. Well deserved.

Thanks.

Hey, good morning, Travis. Was curious on the triple-stacked laterals.

As you see that come online and watch that, is that something that you’d look to maybe kick off as a program going forward as maybe the best way to develop these, given that all of those formations are really showing some good results? Or just what are your thoughts around if that’s successful what we’re looking for going forward?

Yes, Jason, I think that’s a reasonable expectation. Certainly as we move into Glasscock and Howard County, triple and quadruple-stacked laterals appear to be the best way to go.

One of the reasons is that each of the zones there are so close in their economic performance that the returns you get from each zones are very similar, so it makes more sense to try to get as many of those up and down as you can while you got the rig parked at the surface.

Okay. And you mentioned, obviously, the good results so far at least with the higher sand content.

Are there any other things that you’re seeing besides that that you’re maybe still tweaking as you work on these completions? Or are you pretty much pretty happy with you’re seeing and just kind of doing a few one-offs, if you will, to see if things are going to even get better?

I think we’ve got a really good completion organization that’s never satisfied with what the current thinking is. They’re always trying to tweak.

And there’s things with fluids, there’s things with sand concentration, there’s things with cluster spacings, all of which they continue to try to figure out ways to get more oil out of the ground cheaper. And they’ve done a good job so far and I look for them to continue to push the envelope on the completions side.

But there’s not one particular technology that I’d point to that we’d want to highlight right now.

Thanks. Good morning, everybody.

Just a question on kind of the maintenance CapEx levels you guys foresee going forward? Just trying to get a sense on if commodities were to stay low at these levels, at what rig counts would CapEx levels would you need to keep production flat as you look into 2016?

I think if you just look at what we did in the second quarter, where Tracy highlighted that we were cash flow positive in the second quarter, somewhere between two horizontal rigs and three horizontal rigs, depending on how fast we continue to drill these wells, but somewhere between two horizontal rigs and three horizontal rigs would keep our production flat.

Okay. Thank you.

And then with the new completion designs, with the greater proppant loadings, what do you need to see there to do that across all your completions? Yes, I guess that’s my question.

As we’ve said, we’ve done it on three wells in our Spanish Trail area, all of the Wolfcamp B, the early results went good. We just need a little more time to make sure it truly is incremental reserves as opposed to just acceleration.

But as we mentioned, we’ve got additional tests planned for the remainder of this year, not just in the Wolfcamp B but also in the Spraberry. So in this low commodity price environment we just want to make sure that for incremental dollars that we are achieving incremental returns, so we’ll continue to monitor.

Good morning, everyone. The five additional completions added in 2015, should we assume those are more back-end loaded in the fourth quarter and more additive to 2016 production versus 2015, or how should we look at that?

Yes, Gail, that’ll be late 4Q, so it’ll be exit rate impact and then 1Q 2016 impact.

Okay, great. And then you talked about the current commodity price environment, there would need to be another kind of recalibration of service costs and lower well costs to kind of support acceleration of activity.

I’m just kind of curious on what’s left to give on the service environment? I mean I know most of these guys have cut pretty decently; some guys are below maintenance CapEx on some of their equipment.

And then when you kind of look at the current environment is there any concern kind of in the couple years forward out , like, maybe 2017 timeframe that because the cuts have been so dramatic that there’s going to be a lack of equipment from that standpoint?

Yes, just in reverse order there, Gail, Yes, I think there could be a lack of equipment, particularly on the pressure pumping side, because that equipment is – the stuff that’s working right now, that’s pretty extreme environments that they have to work in. And there’s not a lot of capital investment right now to replace pressure pumping equipment.

So when oil responds, and it will, and activity picks up, we as an industry are going to have to figure out how to meet that increased activity on the pressure pumping side. I believe rigs are probably right behind that, but there’s still a lot of rigs out there right now that aren’t working.

And then how much the service sector can continue to go down? I don’t know, Gail.

You’re going to have to ask those guys how much more concessions they can give to allow it to go to work because that’s essentially what the industry is saying is that if you want steady work probably at these oil prices, there’s probably another leg down in costs that are going to be expected.

Okay, great. And then just one quick clarification.

We saw the oil composition volumes – oil composition and percentage of volumes tick down this quarter. It was up 1Q versus 4Q.

Going forward, should we kind of think you’re back into that more normalized 75% range? Just out of curiosity.

Sure. Yes, we went back and looked at all of 2014, each quarter.

Besides the first quarter of 2014, we averaged right at that 75% oil. As you recall, we had a nice volume beat in the first quarter, and one of the reasons that we did have such a good volume story was we brought on several multi-well pads early on in the quarter that came on at extremely high oil cuts.

We’ve looked at July, we were running right around 74.5%, 75% and so far in August, we’re running at about 75%. So consistent with our guidance, I think, we ought to be using around 75% oil.

Hi. Good morning, folks.

I had a quick question. We haven’t heard anything on Howard County.

I know it’s really only been six weeks since you closed that deal. I’m just curious how you’re thinking about any activity on that area, I guess over the next, call it, six months to 12 months?

Yes. We plan to have a rig there really late, late fourth quarter or certainly early first quarter.

And depending on what our rig cadence looks like in 2016, we’ll either have one rig or two rigs working in Howard County.

Okay. And then have you determined kind of what zones you would attack first?

Yes. We’ll go over there and do triple – probably triple-stacked laterals in the Lower Spraberry, Wolfcamp A and Wolfcamp B.

Okay, great. That’s helpful.

And then a question on the Lower Spraberry. I know around year end 2014, and please correct me if I have numbers wrong, I think you – there was talk about 20 Lower Spraberry PUDs on your books and I think you talked about having about 275 sort of engineered locations that you felt were fully derisked.

In your presentation, you talk about, I think, a 368 location count that could go up another 80-plus locations with downspacing. Are those – do you consider those all derisked based on your operator activity?

Or kind of like, how comfortable do you feel with the entirety of your Lower Spraberry footprint?

Yes, the 260 locations, those we feel really good about because we’ve got tests in each of those areas, those are the kind of the western side of the basin, Midland, Martin, Northeast Andrews County. So as you know, we’ve got quite a few Lower Spraberry wells in Spanish Trail, we’ve got our tests in Southwest Martin as well as offset operators.

We’ve drilled some more wells up in Northwest Martin that just have been on now for about three weeks that look real good. So, Yes, we feel really good about the western side of the basin.

We’ve also got offset operator results on the eastern side of the basin, particularly in Howard County. There’s not as many wells in Lower Spraberry and Glasscock, but you’ve got the Pioneer Lower Spraberry wells, that’s up a little bit northwest of our acreage, that looked really good.

And based on all our petrophysical work, we feel good about Glasscock as well. I think the questions there in Glasscock are more about what the ultimate recoveries will be.

We certainly feel like the productivity is going to be pretty good there.

I wanted to circle back on the triple stack concept and maybe just pad development in general. Just kind of wondering how you guys are thinking about balancing the longer spud-to-sales times of larger pads versus translating that into cash flow.

In the near term, what’s kind of your sense for an average pad size that you guys are comfortable with, given the kind of four-rig or five-rig program that you guys are moving towards?

Yes, Jeff, it looks like our most frequent pad size will be either three wells or two wells going forward. And that does have an impact on cycle time.

But again, as we’ve demonstrated, we continue to drill these wells faster and faster. And so we’re trying to offset some of the inherent delays with pad drilling by shorter cycle times associated with the drilling and completion operations.

Okay. And then wanted to get your thoughts on hedging for 2016.

Obviously, I know right now is probably not a good time to be layering anything on, but I think in the past, you talked about maybe $65 was kind of a number you thought would interest you in adding some hedges. Has that changed at all with the recent leg down you’ve had on your cost structure, or what are your thoughts as it stands today for hedging moving forward?

Right. Yes, your first comment was still good, layering hedges on today, I think the quote I saw morning was $50 a barrel of whatever.

So we’re a lot more constructive long term on oil prices than $50 a barrel. So, Jeff, as I communicated in my prepared remarks, we’ve got a balance sheet that allows us the opportunity to go either direction.

We don’t necessarily have to layer on a lot of hedges. We have another form of liquidity that’s non-debt and non-dilutive in our Viper ownership as well, too.

So we have levers to crank on that perhaps some others don’t. But if oil is suddenly at $65 a barrel, I think I’d get pretty interested in putting some hedges on for next year.

Okay. That’s helpful.

And then one more if I can sneak it in on the Viper side. Just wondering with this most recent dropdown of the override, curious to get a sense for what you think the opportunity set is for similar type of transactions between the companies moving forward with the existing assets that you guys have?

Well, we’ve continued to look at the value proposition in doing joint bids with Diamondback and Viper. And we think that that’s a real meaningful way to continue to acquire, where Viper can bid on overrides of a property and Diamondback buys on the standard leasehold, typically burdened at 25%.

And a good example of that is what we did in that recent acquisition in northwest Howard County. We think that’s the business model going forward, and we’re pushing on that lever pretty hard.

Thanks. Good morning.

Just curious on the 500-foot spacing tests, can you just remind me on your views on the Wolfcamp and any plans to test 500-foot spacing in the Wolfcamp at any point?

At this point, we’re pretty happy with our 660-foot spacing based on the data that we have and data that other operators have as well. So at this point, we don’t have any plans to try to tighten up the spacing in the Wolfcamp.

Generally in the Wolfcamp, there’s more barriers to frac height growth, so we think we’re generating effective longer lengths. So that’s the reason we think the 660-foot spacing is good in the Wolfcamp, at least in the areas that we have developed so far.

As we get into Howard and Glasscock County, we’ll just have to gather data there to give us a direction to go.

And are either the Wolfcamp or the Spraberry, are the thicknesses in either of them such that you might be able to do some sort of stacked-staggered configuration?

As you know, as we’ve indicated before, the Wolfcamp, particularly in the Glasscock County, stuff is quite a bit thicker. So the plan there would be to do a staggered pattern within the A and B in those areas.

Okay. And the 500-foot wells are actually outperforming your curves a little bit on that slide eight.

Is there anything to read into that or is that just normal distribution of results?

I would say that’s too early to tell. It could be just normal variation in reservoir quality.

It could also be, too, that we’re getting some enhanced fracturing at the tighter spacing as well. But, again, just need more well data to figure that out.

Okay. And then with the 660-foot spaced wells that are on that chart, do they have offsetting wells on both sides?

Generally they do not. But as we’ve looked at the performance, those are generally three-well pads.

And so, in general, the middle well of the three-well pads is performing similarly to the outer wells up to this point.

Okay. And then on the quarter itself, was there any material amount of downtime from frac protect or anything along those lines that we ought to keep in mind?

And then is that something that might become a greater phenomenon to be aware of as you move forward in a more focused manner and a more development type manner in Spanish Trail and other places?

Yes. Michael, Diamondback, we’ve got almost 175 horizontal wells drilled on our acreage right now.

So the effect of watering out these offset horizontal wells, it’s material, but we’re also experienced enough in it now that we provide coverage for that in our guidance. We take that into account.

So I wouldn’t expect any more or less going forward than what we’ve experienced in the past.

Okay. And if we’re thinking about that downtime and how you factor that into your modeling, is there any way to quantify it relative to, let’s say, the type curves on slide eight that are normalized for operational shut-ins?

What sort of percentage downtime or I don’t know what sort of factor you would apply to that in a hypothetical case.

Michael, what we always try to do on our existing production is what we just – the PDP production line, we always haircut that a little bit to account for weather interruptions and standard oil field occurrences. And then when we look at the new wells, we typically risk those even a little bit heavier to account for that water-out effect that you asked about earlier.

It varies a little bit and we go back every year and look at what the effect is, and we adjust it going forward. But it’s something that we do here internally.

Okay. Fair enough.

And then you mentioned a couple times the potential to use Viper units as a source of liquidity. I just wondered if you could provide additional color around your thinking there in the context of the potential to use that as a source of acceleration capital in 2016.

Just any other color you could provide on that would be appreciated.

Yes. Sure, Michael.

It’s just a tool we have in our tool kit that we don’t think anybody else has that as I focused on, it’s non-dilutive and it’s non-debt. We recognize that.

We own something – we own 88% of something that’s worth over $1 billion. And that just provides us a lot of optionality going ahead.

So I can’t provide exact color on how we might ultimately use that, but it’s certainly a tool that we have.

Thank you, Crystal. Thanks again, everyone, for participating in today’s call.

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