Diamondback Energy Inc (FANG) 2015 Q2 法說會逐字稿

Good day ladies and gentlemen, and welcome to the Diamondback Energy and Viper Energy Partners second quarter 2015 earnings call. At this time all participants are in a listen-only mode. Later we will conduct a question and answer session, and instructions will follow at that time. (Operator Instructions). As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Adam Lawlis of Investor Relations. Sir, you may begin.

Thank you. Good morning, welcome to Diamondback Energy and Viper Energy Partners joint second quarter 2015 conference call. During our call today we will reference an updated investor presentation which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, CEO, 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 conditions, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are made 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 in the reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I will now turn the call over to Travis Stice.

Thank you Adam. Welcome everyone, and thank you for listening to Diamondback 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 are 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 free fall, 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 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 and 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 to 32,000 BOEs a day, from 29,000 to 31,000 BOEs a day 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 this 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 cost for the year to be within the $6.2 million to $6.7 million range for a 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 price. 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 Trails are outperforming offset completions by an average of 15% to 20% for a similar increase in cost. We will closely monitor these results, and we 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 re-align 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 pure leading efficiency and execution continues, resulting in cheaper wells and driving differential returns for 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 is apparent that our focus on capital discipline and stockholder returns has enabled us to be very opportunistic during this down cycle. In fact, either way you look at it Diamondback is positioned to succeed. Win or rebound, 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 a 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 was up 6% from $103 million in the second quarter of 2014. Our second quarter average realized price per BOE, including the effective 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 see cost concessions, and to implement Best Practices on acquired acreage. Our cash, general and administrative costs were $1.24 per BOE, while our noncash 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 that 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 will 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 28th 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 30th 2015. In early July of 2015, Viper completed the purchase of an approximate 1.5% average overriding royalty interest on certain of Diamondbacks' acreage, primarily located in Howard County for $31 million.

Turning to Viper's guidance, we expect 2015 volume in the range of 4800 to 5100 BOE per day, up from the prior range of 4,600 to 5,000 BOE per day. As a reminder, Viper does not incur lease operating expenses or capital expenditures. I will 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 have 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.

Thank you. (Operator Instructions). Our first question comes from Dave Kistler from Simmons & Company. Your line is now open.

Good morning, guys.

Good morning, Dave.

Travis, just to 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 your acquisitive nature of Diamondback, a little about where you see the M&A market similar to how we saw recalibration of service costs with the lower commodity prices, should we see a 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, six, 12 months?

That's a good question. My track record has always been to not to talk about any specific deals we have going on, but it is also reasonable that every trade that occurs in the Permian Basin, Diamondback shareholders should expect 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 expectation to 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 we go forward. Additionally I think there is potentially going to be some more distressed assets coming, maybe coming on the market late this year or early next year, if we stay in the period of prolonged commodity prices. I think there is going to be some opportunities for Diamondback shareholders. We will just have to wait and see how it plays out until we get some solutions around some of the macro issues that I referenced.

Thank you. 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?

If you go back to the time frame right after our IPO, crude was in a pretty good decline right after Viper IPO. I think our experience shows that it is difficult to convince sellers to convert their ownership into Viper units when commodity prices are still going down. I think you need a little stability in the commodity price, before you get increased interest from sellers, or guys that want to trade their interest for Viper units. That being said, our pipeline is still pretty full right now. We are pleased at the progress we have made. In terms of furthering these deals along, we have not closed any, and they have not traded away from us either. The market is a little bit in flux right now. We will have to see over the next several months whether or not we can be doing an accretive deal for our Viper shareholders.

Appreciate that. One last one. In the press release you highlighted some of the positive down spacing results that you've seen so far. Can you talk about the length of time you need to see those wells produce, before you can have confidence with officially highlighting potentially more inventory across your portfolio?

This is Russell. If you go to our slide deck on slide eight, we have changed it up a little on how we showed that result. So we show an average for our 500-foot space wells versus our 660-foot space wells, and our other singular wells that don't have any offsets. Today 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 space wells that we have right now are essentially two well pads. You don't have the full offsetting wells. We are continuing to drill 500 foot spaced wells in Spanish Trails, and by the end of the year we will have a full half section developed with five wells. Once we get those results, I think we will have a more definitive answer. We are certainly encouraged by the results so far, where we have got almost six months of data on the first 500 foot wells that still look very good.

Great. I appreciate that. Thanks for the added color, guys.

Thanks, Dave.

Thank you. Our next question comes from David Amoss from IBERIA Capital Markets. Your line is open.

Good morning, guys.

Good morning, David.

Travis, trying to wrap my hands around potential scenarios in 2016. Two specific questions. First, can you kind of point us in the direction of your inflection points on the commodity, and what that might mean in terms of activity levels? Say in a $40 case and a $60 case? And same question on well costs. I know you said your average well costs for the year 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 update us on where you are, and where you might go, considering what is going on with the commodity going down recently?

Certainly, Dave I will answer those in reverse. Our current well costs are below $6 million for a 7,500-foot well. And we felt like that was going to be the bottom of well costs. But now oil has taken another leg down, and I think it is reasonable to expect the service sector will respond with another step down in cost as well too. What that will be and when that will occur I am not exactly sure. But I know the activity is going to continue, there has to be another recalibration if oil is in that $40 to $45 range.

Again specific, you asked some specific questions on 2016, David, there is so much flux in the market right now. Not only with the macro issues that we talked about with the previous question, I am just not ready to talk specifically about what 2016 looks like. What I have tried to communicate is we focused on returns to our shareholders. And to the extent that we can still generate returns to our shareholders, we will keep some level of activity in 2016, to the extent things haven't recalibrated, we will show that same behavior we did earlier this year, and we will slow down the capital spending, and we will return to somewhere within cash flow, or close to cash flow. I know that all of the questions on the call you are curious about how to model 2016. The reality is, we have got to get some stability in the market place before Diamondback is going come out with a very prescriptive year of 2016.

Thanks. And one quick follow-up. You guys have made great efficiency gains so far this year. Can you give us an order of magnitude, in terms of what we can expect over the next 12 months?

I already mentioned that if commodity prices stay low, we think that there will be another 5% to 10% of cost concessions that will be offered up by the service sector. In terms of efficiency gains, we are probably somewhere around 30% or so right now, of total cost concessions. Of that 30% probably 10% or so is what we are going to call permanent savings. We are looking to increase that number even further. That's not a new thing for us. We have been doing that all along which is one of the reasons our execution performance is what it is. We think there are still some more pennies to pick up, and we intend to pick them up and pass them back on to our shareholders.

That's helpful and congratulations on a good quarter.

Thank you, David.

Thank you. Our next question comes from Neal Dingmann from SunTrust. Your line is open.

Good morning. Travis, I saw not too long ago this morning, I see Exxon has picked up another 40,000. It says here in the core Midland. Two questions around that. One, I guess when you look at competition to find acreage either near or around you, how do you view it today versus say even a year ago, when we were not in a higher commodity market?

Certainly Neal where Diamondback's almost 85,000 acres sits, most of that is in what the industry is defining as perhaps the most lucrative investment shale horizon in the US. And that viewpoint has not done anything but gotten stronger over the last 12 months, as Diamondback and other operators continue to post really impressive well results and cost performance on these wells. Even in the backdrop of declining commodity prices, this rock continues to impress to the positive, and that just means that makes the demand for that rock that is 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 on this one it shows that an acquisition and farm in, you are open to any 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 is a meaningful way to move into acreage. So yes we have considered and offered numerous drill to earn type of opportunities.

Thank you.

Thank you.

Our next question comes from Mike Kelly from Global Hunter Securities. Your line is now open.

Thanks. Travis, you mentioned that Diamondback will continue to grow as long as you are seeing strong returns. I would 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 the year. What is kind of your limit on that where you want to back off? On the other side of that, you talked about potentially going up to eight rigs next year, what do you need to see to step on the gas, and maybe accelerate that rig count? Just from that returns perspective? Thanks.

Mike, I did mention the remaining wells we have to drill this year are all somewhere between 40% and 50% rate of return. It is hard to argue with that kind of returns, to not continue to deliver that to my shareholders. If we stayed at being able to generate rates of returns that robust, I think you would look to us to continue to stay at either the level we are at right now, or maybe even a slight increase. To get to 7, 8, 9 rigs, we have got to have another recalibration of service costs and commodity prices. I am not sure exactly what oil price that translates to, but that's how we are looking at the world right now, Mike.

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

Yes, we are currently using for planning purposes about 18 wells per year per rig. That is down from probably 20 to 21 last year and maybe even 20 the other way, so about 18, oh yes we are using 12, I'm sorry, I got that backwards. We are using about 12 wells per rig last year, and we are now at about 18. And we've got actually designs on as many as two wells a month per horizontal rig for a 7500-foot lateral. We are continuing to push the envelope and that's where we are at right now.

Appreciate that. Congratulations to the Hollis University and the promotion there. Well deserved. Thanks.

Thank you. Our next question comes from Jason Wangler from Wunderlich. Your line is now open.

Good morning, Travis. On the triple stacked laterals as you see that come online and watch that, is that something you would look to see kick off as a program going forward as maybe the best way to develop these given all of those formations are really showing some good results? What are your thoughts around if that is successful, what we are looking for going forward?

Yes, I think that is 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 zone are very similar, so it makes more sense to try to get as many of those up and down as you can, while you have the rig parked at the surface.

And you mentioned obviously the good results so far at least with the higher sand contents. Are there any other things that you are seeing besides that, that you are still tweaking as you work on these completions, or are you pretty happy with what you are seeing, and just doing a few one offs to see if things will even get better?

I think we have got a really good completion organization, that is never satisfied with what the current thinking is. They are always trying to tweak, and there are things with fluids, there are things with sand concentration, and there are things with cluster spacings. All of which they continue to try to figure out ways to get more oil out of the ground cheaper. They have done a good job so far, and I look for them to continue to push the envelope on the completion side. There is not one particular technology that I would point to that we would want to highlight right now.

Great. I will turn it back. Thank you.

Thank you. Our next question comes from Gordon Douthat from Wells Fargo. Your line is now open.

Good morning, thanks, everybody. Just a question on 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, what CapEx levels would you need to keep production flat as you look into 2016?

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. Something between two and three horizontal rigs, depending on how fast we continue to drill these wells. But somewhere between two and three horizontal rigs we keep our production flat.

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 of your completions? I guess that's my question.

As we said we have done it on three wells in our Spanish Trail area, all in the Wolf Camp B, the early results. We just need a little more time to make sure it is truly incremental reserves, as opposed to just acceleration. As we mentioned, we have got additional tests planned for the remainder of this year, not just in Wolf Camp 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 will continue to monitor it.

Thank you.

Thank you. Our next question comes from Gail Nicholson from KLR Group. Your line is now open.

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 would be late 4Q, so it will be exit rate impact and then 1Q 2016 impact.

Great. You talked about the current commodity price environment there would need to be another 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 know most of these guys have cut pretty decently, some are below maintenance CapEx on some of their equipment. And when you look at the current environment, are there any concerns in the couple years forward out like maybe 2017 time frame, that because the cuts have been so dramatic, there will be a lack of equipment at that standpoint?

Yes, just in the reverse order there, Gail. I think there could be a lack of equipment, particularly on the pressure pumping side. Because that equipment, the stuff that is working right now is being, it is pretty extreme environments that they have to work in. There is not a lot of capital investment right now to replace pressure pumping equipment. 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. There are still a lot of rigs out there right now that aren't working.

And how much the service sector can continue to go down, I don't know, Gail. You are going to have to ask those guys how much more concessions they can give to allow to go to work because that's essentially what the industry is saying is that if you want to stay to work, at these oil prices, probably another leg down in costs that are going to be expected.

Great. And then one clarification. We saw the oil composition volumes, the oil composition and percentage of volumes ticked down this quarter, it was up 1Q versus 4Q. Going forward, should we thinking you are back to that more normalized 75% range? Just out of curiosity?

Yes, we went back and looked at all of 2014, each quarter, and 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 have looked at July and we were running right around 74.5%, 75%, and so far in August we are running at about 75%. Consistent with our guidance we ought to be using around 75% oil.

Great, thank you so much.

Thank you. Our next question comes from Tim Rezvan from Sterne Agee. Your line is now open.

Good morning folks. Quick question, we haven't heard anything on Howard County. I know it has really only been six weeks since you closed that deal. I'm just curious how you are thinking of any activity on that area over the next call it six to 12 months?

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 will either have one or two rigs working in Howard County.

And have you determined what zones you would attack first?

We will do probably triple stacked laterals in the lower Spraberry, Wolf Camp A and Wolf Camp B.

Great. That's helpful. And a question on the lower Spraberry, I know around year end 2014, and please correct me if I have the numbers wrong. 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 talked about I think about a 368 location count, that could go up another 80-plus with downspacing. Are those, do you consider those all derisked based on your operator activity? How comfortable do you feel with the entirety of your lower Spraberry footprint?

The 260 locations, those we feel really good about, because we've got tests in each of those areas. Those are the western side of the basin, Midland, Martin and northeast Andrews County. As you know, we have got quite a few lower Spraberry wells in Spanish Trail. We have got Arch S in southwest Martin, as well as offset operators. We have drilled some more wells in northwest Martin, that they have just been on now for about three weeks that look real good. So we feel really good about the western side of the basin. We've also got offset operators on the eastern side of the basin, particularly in Howard County. There are not as many wells in lower Spraberry in Glasscock. But you have got the Pioneer lower Spraberry wells, that's a little northwest of our acreage that looked really good. Based on all of 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.

Appreciate the color. Thank you.

Thank you.

Our next question comes from Jeff Grampp from Northland Capital Markets. Your line is now open.

Good morning guys. Wanted to circle back on the triple stack concept, and just pad development in general. Wondering how you guys are thinking of balancing the longer spud to sales times with larger pads, versus translating that into cash flow in the near term? What is your sense for an average pad size that you are comfortable with, given the four or five rig program that you are moving towards?

Jeff it looks like our most frequent pad size will be either three or two wells going forward, and that does have an impact on cycle time. Again as we have demonstrated, we continue to drill these wells faster and faster, and so we are trying to offset the inherent delays with pad drilling by shorter cycle times associated with the drilling of the completion operations.

And then wanted to get your thoughts on hedging for 2016. Obviously I know right now it is probably not a good time to be learning anything on. In the past I think you talked about 65 was a number that you thought would interest you in adding some hedges. Has that changed at all with the recent leg down you have had on your cost structure, or what are your thoughts as it stands today for hedging moving forward?

Your first comment was still good. Layering the hedges on today, I think the quote I saw this morning was $50 a barrel or whatever. We are a lot more constructive long term on oil price than $50 a barrel. Jeff, as I communicated in my prepared remarks, we have 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 is non-debt and non-dilutive in our Viper ownership as well too. We have levers to crank on that perhaps some others don't. But if oil was suddenly at $65 a barrel, I think I would 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 drop down of the override, curious to get a sense for what you think the opportunity set is for a 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. We think that is a real meaningful way to continue to acquire, where Viper can bid on overrides of a property, and Diamondback buys on just 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 is the business model going forward, and we are pushing on that lever pretty hard.

Great. Thanks for the color, guys.

Thank you. (Operator Instructions). And our next question comes from Michael Hall from Heikkinen Energy Advisors. Your line is now open.

Thanks, good morning. Just curious on the 500-foot spacing tests. Can you remind me on your views on the Wolfcamp, and any plans to test 500 foot spacing on the Wolfcamp at any point?

At this point we are happy with our 660 foot spacing based on the data that we have, and the data other operators have as well. At this point we don't have any plans to tighten up the spacing in the Wolfcamp. Generally the Wolfcamp there are more barriers to frac high growth, so we think we are generating effective longer lengths. That's the reason we think the 660 foot 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 will just have to gather data there to give us a direction to go.

Are either the Wolfcamp or the Spraberry such, are the thicknesses in either of them such that you might be able to do some stack stagger configuration?

As we have indicated before, the Wolfcamp particularly in the Glasscock County stuff is quite a bit thicker. 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 on that slide 8. Is there anything to read into that or is that normal distribution of results?

Yes, I will tell you it is too early to tell. It could be just normal variation in reservoir quality. It could also be too, that we are getting some enhanced fracturing at the tighter spacing as well. Again, just need more well data to figure that out.

And those 660-foot space wells that are on that chart, do they have offsetting wells on both sides?

Generally they do not. As we have 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 have got to keep in mind? And is that something that might become a greater phenomenon to become aware of, as you move forward in a more focused manner and a more development-type manner in Spanish Trail and other places?

Michael, Diamondback, we have almost 175 horizontal wells drilled on our acreage right now. The effect of watering out these offset horizontal wells, it is material, but we are also experienced enough in it now that we provide coverage for that in our guidance. We take that into account. I wouldn't expect any more or less going forward than what we have experienced in the past.

If we are thinking about that downtime and how you factor that into your modeling, is there any way to quantify it, relative to the type curves on slide eight that are normalized for operational shut in? What percentage downtime, or I don't know what sort of factor you would apply to that hypothetical case?

Michael, what we always try to do on our existing production is the PDP production line. We always haircut that a little bit to account for weather interruptions and just standard oil field occurrences, and then when we look at 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 affect is, and we adjust it going forward. It is just something that we do here internally.

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 can provide any additional color on your thinking there, and the context of the potential to use that as a source of acceleration capital in 2016? Any other color you could provide on that would be appreciated.

It is just a tool that we have in our tool kit that we don't think anybody else has. As I focused on, it is non-dilutive, and it is non debt. We recognize that we own something, we own 88% of something that is worth over $1 billion, and that just provides us a lot of optionality going ahead. So can't provide exact color on how we may ultimately use that, but it certainly is a tool that we have.

Fair enough. Appreciate it. Thanks.

Thanks, Michael.

Thank you. And that does conclude our question-and-answer session for today's call. I would now like to turn the call over to Travis Stice, Chief Executive Officer for closing remarks.

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

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program. You may all disconnect. Everyone have a wonderful day.