Good day, ladies and gentlemen, and welcome to the Diamondback Energy Fourth Quarter 2016 Earnings Conference Call. At this time, all participant lines are in a listen-only mode to reduce background noise but later, we'll be holding a question-and-answer session after the prepared remarks and instructions will follow at that time.

As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Adam Lawlis, Manager, Investor Relations. Sir, you may begin..

Thank you, Andrew. Good morning, and welcome to Diamondback Energy's fourth quarter 2016 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; 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'll make reference to certain non-GAAP measures.

The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. As a reminder, Viper Energy Partners, a subsidiary of Diamondback, will be hosting its first standalone conference call at 10:00 a.m. Central today. Dial-in details can be found on Viper's 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 fourth quarter 2016 conference call. 2016 was a transformational year for Diamondback, with two halves of the year that could not have been more different.

We reacted appropriately to the unprecedented decline in commodity price in the first half of the year by deferring completion activity and subsequently responded quickly with increased activity and asset acquisitions in the second half of the year.

We are working diligently to close the second acquisition, a $2.4 billion purchase of the assets of Brigham Resources. Upon the closing of this acquisition at the end of this month, Diamondback will have more than doubled our Tier 1 acreage and added our sixth and largest core operating area of 1 million barrel EUR wells.

Our confidence in the resource potential of this asset is based on more than 50 producing horizontal wells positioned across the acreage. The Wolfcamp A will receive the majority of our capital in the near term, but there remains substantial upside in multiple other zones with several years of inventory ahead of us.

We will complete this transaction at an acreage value that allows Diamondback to achieve full cycle returns that continue to be industry-leading. We expect the deal to be immediately accretive on all financial metrics as well as to our corporate wide oil cut.

As a result of this acquisition, we will have the inventory to grow at industry-leading rates within cash flow for multiple years, and our focus now concentrates on resource execution, converting rock into cash flow most efficiently.

The contiguous nature of the overall acreage position fits with our focus on operational efficiency, and we expect to achieve the same best-in-class drilling and completion results in the Delaware Basin that we are known for in the Midland Basin.

From an operational standpoint, we are operating six rigs today; five in the Midland Basin and one in the Southern Delaware Basin. We expect to add two rigs to the Brigham position after closing. Diamondback continues to proactively manage service cost inflation.

We could potentially increase our operated rig count to ten rigs in the back half of the year should commodity prices continue to strengthen.

As a result, we are increasing our 2017 production guidance, a range which implies over 65% production growth at the midpoint and positions us to continue to have multi-year organic growth at or near cash flow breakeven prices at current strip. Q4 2016 production of nearly 52,000 barrels a day was up 16% quarter-over-quarter and 38% year-over-year.

Average daily production for 2016 was 43,000 barrels a day, which exceeded the high-end of our range of 41,000 to 42,000 barrels a day and is up 30% year-over-year. 2016 proved reserves increased over 30% from 2015 to more than 205 million barrels, 68% of which are oil.

I am particularly proud of our proved developed finding and development costs of $7.26 per barrel.

Diamondback continues to deliver on its corporate mission of best-in-class execution and low cost operations with cash operating costs decreasing 7% quarter-over-quarter to less than $8.50 a barrel, including LOE below $5 a barrel and cash G&A less than $1.00 a barrel. Our 2017 LOE guidance at the midpoint is 9% of our 2016 guided range.

We continue to be pleased with the strength of our well results throughout our asset base, which Mike will elaborate upon later. As shown on slide 4, we have accumulated a strong inventory with six core areas with wells capable of 1 million barrel-plus EURs.

In each of these areas, we are focused on long lateral development with more than 80% of our locations having 7,500 foot or longer laterals. We have now built a legacy company with an asset base that we expect will, at current strip prices, allow us to grow at best-in-class rates within cash flow for many years to come.

I'll now turn the call over to Mike..

Thank you, Travis. Diamondback continues to post encouraging results and achieve new company execution milestones. Turning to slide 5, Diamondback continues to increase our conservatively booked oil weighted reserves. 2016 reserves increased 31% to 205 million BOE, replacing 409% of production, 380% of which was organic.

Showcasing our conservative approach to booking, 58% of our reserves booked are proved developed with only 2% of those reserves attributed to the Delaware Basin. This illustrates the tremendous reserve growth that Diamondback has in front of us.

We have continued to demonstrate our peer-leading capital efficiency with drill bit F&D at $6.31 per BOE and PDP F&D at $7.26 per BOE. Slide 7 shows our continued success in Howard County, where we believe we had demonstrated economic results across three zones and plan to run one rig continuously in the area.

As you can see, the well results on our second operated pad, the Reed pad, have well-exceeded the performance of our first. Diamondback continues to maintain a rate of return-focused completion optimization program.

On the Reed pad, we optimized well placement within the reservoir and utilized a stack and staggered approach while monitoring with microseismic. We also applied high-density near-wellbore stimulations, including the use of diverting agents.

After producing over 100,000 BOE in 125 days, the Reed Lower Spraberry well continues to produce over 1,100 barrels a day, of which 89% is oil. Slide 8 also illustrates the top quartile inventory we possess in Glasscock County.

The Ray wells have shown impressive results; getting confidence these wells will exceed an average of a 1 million barrel type curve. After producing roughly 85,000 BOE each in 80 days, the Ray WA wells, Wolfcamp A wells, continue to produce over 1,400 BOE a day each.

We've also completed our second and third Lower Spraberry wells and with these encouraging results, we plan to run one rig continuously in Glasscock County through 2017.

On slide 9, we provide an update on the continued success of our under-appreciated 1 million barrel type curve Lower Spraberry well results in Andrews and northern Martin counties where again we intend to stay active in 2017.

Our plan is to run two to three rigs in Midland County in 2017 where we continue to have exceptional results, and well economics are further supported by Viper's ownership in minerals. Our optimized stimulation has become our standard design for the four proven zones in Midland County.

Slides 11 through 15 describe our plans and recent activity on or near our current Southern Delaware Basin assets. We commenced drilling operations on this asset in January and will focus a majority of our 2017 drilling activity in the Wolfcamp A.

Since the time of the acquisition, we have increased our working interest from 49% to 73% thanks to trades in bolt-on acquisitions. Our Brigham acquisition is still expected to close at the end of this month, and we plan to complete five DUCs and operate two rigs post-close.

Our Southern Delaware asset provides a large runway for future growth as our asset base could allow for up to 10 operated rigs in the future. Turning to operations and execution, slide 17 demonstrates our continued track record of execution as DC&E costs are down 41% from 2014, while our average completed lateral length is up about 30%.

We have forecasted service cost inflation in our 2017 CapEx budget, primarily from completions. We are proactively mitigating these costs where appropriate. For instance, we are de-bundling services and have a large percentage of tubular goods forward purchased.

Slide 19 reflects our spacing assumptions relative to our peers, leaving considerable upside from downspacing potential. 86% of our pro forma locations have a lateral length of 7,500 feet or longer. Diamondback has been successful at bolting on and trading to block up acreage.

Longer laterals are more capital efficient and provide a higher rate of return for our shareholders. Slide 20 shows reductions to our operating expenses since the peak in 2014. Total LOE spend for 2016 was essentially flat with 2015, despite production increasing 30% over the same period. Fourth quarter LOE was $4.89 per BOE.

We've recently reduced our 2017 LOE guidance range to $4.75 to $5.75 per BOE compared to $5.50 to $6 per BOE in 2016. And that's due to improved pumping practices, lower well failure rates, and increased horizontal production. With these comments now complete, I'll turn the call over to Tracy..

Thank you, Mike. Diamondback's fourth quarter 2016 net income was $26 million or $0.32 per diluted share. Our net income adjusted for noncash derivatives, and the premium paid for early refinancing of our senior notes was $72 million or $0.90 per diluted share. Our adjusted EBITDA for the quarter was $138 million, up 35% from Q3 2016.

Diamondback's average realized price per BOE, including hedges for the fourth quarter of 2016, was $38.09. During the quarter, our cash G&A costs were $0.92 per BOE while non-cash G&A was $1.22.

During the quarter, Diamondback spent approximately $104 million on drilling and completions, $10 million on infrastructure, and $8 million on non-operated property. We spent an additional $87 million on acquisitions during the fourth quarter, including approximately $68 million at the Viper level.

As shown on slide 23, pro forma for our pending Brigham acquisition, Diamondback ended the fourth quarter of 2016 with a net debt to Q4 annualized adjusted EBITDA ratio of 1.5 times. On slide 25, we provide our guidance for the full year 2017.

Diamondback increased its 2017 production guidance to a range of 69,000 to 76,000 BOE per day, up 6% from December 2016 guidance. With strong well performance, higher working interest, and increased activities driving the increased outlook, our 2017 capital expenditure guidance has also increased slightly to between $800 million and $1 billion.

We are reflecting some service cost inflation and a six-to-ten rig program with 130 wells to 165 wells completed, assuming an average lateral length of 8,500 feet. At current strip prices, we expect to deliver annualized production growth of over 65% at or near breakeven cash flow.

We will also be spending $75 million on one-time infrastructure projects in the Delaware Basin, investments which on a standalone basis, have returns that rival our operated wells while maintaining best-in-class operating margins. I'll now turn the call back over to Travis..

Thank you, Tracy. Diamondback was able to deliver another strong quarter because of our commitment to execution and low-cost operations. Our production and reserves were up as a result of well performance and accelerated activity. Cost and expenses were down. And we continue to break execution records.

After more than doubling our Tier 1 acreage with our announced acquisitions in the second half of 2016, our focus now shifts to execution. And we think we have an established track record of executing that will aid us as we continue development in the Southern Delaware Basin. Andrew, please open the line for questions..

Ladies and gentlemen, the question-and-answer queue is now open. We'll be taking our first question from the line of John Nelson from Goldman Sachs. Your line is open..

Good morning, and congratulations to the team on a really outstanding quarter..

Thank you, John..

Travis, we're adding a lot of Permian rigs here each week, and a lot of investors obviously focused on oilfield service cost inflation. The team mentioned a lot of times in their prepared remarks you're baking in some level of service cost inflation at 2017 budget. Wondering if we can get any further quantification of what that is that's baked in.

And then maybe you could also tie that in with what are you guys actually seeing in real time, have we really seen the pressures start to build yet?.

Yeah, that's a good question, John. Just mathematically, we've dialed in between a 10% and 15% total well cost increase starting in the first quarter. We're not seeing that just yet. We actually believe that if oil stays kind of range bound between $50 and $55, the impetus behind service cost increases will be muted a little bit.

However, if we continue to see commodity prices strengthen to that $55 to $60 a barrel, we believe that you'll see these service cost increases start to accelerate in the back half of this year. Now it's not that Diamondback is going to acquiesce on these cost increases.

We're working diligently with our service providers and our business partners, like Mike had highlighted, to try to mitigate those costs. We know that for a healthy industry as we continue to build rigs in the Permian, we are going to have to have a service company that's well-capitalized and ready to support increased activity.

I think last week here in the Permian, we eclipsed 300 rigs and we're adding anywhere between five rigs and ten rigs per week. And so if that pace continues, you'll start to see some tightening.

So, we've not just opened our eyes to this phenomenon this quarter; it's something we've been doing really since the back half of last year when all activity increased.

And while we may not be insulated from all service cost increases, we feel like we've been proactive enough to be able to offset some of the service cost increases that we're forecasting. So really, 10% to 15% on the total well cost, the drilling side, we're not anticipating really much if any increase on the drilling side.

All of that increase is really housed on the completion side, primarily under pressure pumping, which means we've dialed in a 20% to 25% increase.

Again, we're not seeing that today, but we are having conversations with our business partners that if activity continues to pick up and demand for those services continues to increase, to expect cost increases..

That's really, really helpful. My second question may be a little bit more higher level. It sounds like there's a little bit of inflection in your messaging here and that Diamondback is going into cash flow harvest mode, so to speak, post Brigham.

If I take a step back, you team's done a really – has an excellent track record of executing accretive bolt-on acquisitions.

And as I think about the year ahead, it would seem to us at least that 2017 could be a year where smaller players learn they maybe can't operate as efficiently as Diamondback as service capacity tightens, potentially compelling them to the negotiating table. So I guess my question is just to be clear on the messaging.

Is it, a) Diamondback has the scale and we're just in digestion mode for the time being? Or is it, b) Diamondback has the scale, but will continue to look at every deal that's in the market should there potentially be more over the course of 2017?.

Yeah, good question, John, and let me get to that. I just want to close the other comment on the service cost increases. We've spent a lot of the last two quarters talking about savings that we had made permanent inside Diamondback Energy.

So with the efficiency gains and the things that we've done institutionally and organizationally in-house, we believe that that also further insulates us from future cost increases. So, we've talked about as much as half of the total savings which are down about 50% from the peak in 2014 being made permanent through efficiency gains.

So, we know that there's going to be some leverage and some cost increase on the other side of the table, as I pointed out, that's needed, but don't forget that Diamondback has really led the way in pushing these savings and efficiency gains to make things permanent.

If you read our press release, we've got a couple of comments in there about how long it takes us to drill one of these wells. That a couple of years ago was taking us – we were drilling about a 1,000 feet a day, and now we're drilling over 2,000 feet a day. And those savings are going to be with our shareholders from now on.

Now specific to your question on acquisitions, yeah, it's not reasonable to think that Diamondback is going to move firmly into just digestion mode. What I said is that from a resource capture side of things, we're very comfortable with our inventory, and it's now all about resource execution.

That being said though, we're going to continue to do the bolt-on acquisitions, the smaller trades that are in the $100 million to $300 million range; it depends, maybe larger. But again, with our enterprise value of over $11 million, almost $12 million right now, it takes something really big to move the needle.

So what I intimated was that the large trades in terms of really building our resource are probably on the sidelines for now.

But what we're really focused on is every quarter, doing these bolt-on acquisitions that allows us to, like you pointed out, be more efficient than the seller and also drill longer lateral or perhaps have addressed the service shortage potential more adequately than the seller. So, we're still in the game.

I've said all along that you're either in the game or out of the game, and we're still in the game..

Great. I'll let somebody else hop on. Congrats again..

Thanks, John..

Thank you. Our next question comes from the line of Pearce Hammond from Simmons. Your line is open..

Good morning, and thanks for taking my questions. Travis, just following up on the question just now on service costs.

If they did accelerate maybe faster than what you're anticipating, would you consider building DUCs?.

If you look at the returns that we have on these wells with those permanent savings that I just got through talking about, I don't think that's reasonable. I think you'd have to see a combination of rapidly increasing service costs coupled with a declining commodity price. I think that's the only time we'd really start having that conversation again.

You've heard me talk about dead capital or stranded capital. That's not a good thing for our investors, and that's what DUCs are. They're least deferred capital. And so as long as the industry moves sort of in lock step with an increasing commodity price, I don't think it's reasonable for us to start building our DUCs again..

Great.

And then, Travis, my follow up is how comfortable are you right now with your current Delaware Basin water sourcing and infrastructure for dealing with produced water?.

Look, Pearce, we take over operations here in a couple of weeks, but we've got a full in-house team dedicated to looking at these issues, not in a micro sense but in a macro sense so that we can address all of those issues with the multi-rig drilling program. And I'll give a shout-out to the Brigham Resources operations team.

They've been dealing with that issue for years and they have been excellent to work with and bringing my guys up to speed, and so it's something that we're very proactive at. We've got a water sourcing team now that focuses on nothing but accumulation and disposal of water.

And while that will be a portion of the infrastructure spend that we've talked about this year, we anticipate doing what we do, which is to get in front of that and be able to feed the multi-rig program we're talking about..

Thanks, Travis, and congrats on a great 2016..

Thank you, Pearce..

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

Good morning, Travis. Travis, one of my question is, a little bit on John, on overall spend.

I know you haven't – I'm certainly not going to hold you to any type as far out as 2018 yet, but you mentioned about spending $75 million on the Delaware infrastructure, and then when I sort of looking at the upstream activity, I guess what I'm looking at as far as how much spend in 2018 do you see could be a bit different than 2017 in terms of not needing as much infrastructure, and then perhaps having more delineation or developmental type drilling? So I guess getting more bang for your buck, if you will, next year, if you comment on that?.

Yes, Neal, we certainly see value proposition on the midstream side of things. And as we pointed out in our prepared comments, there's about I think $75 million of what we refer to as more one-time spending as we get in front of some of the things we need to do to produce this rock very efficiently.

And as you move into 2018, you're right, we've not provided any guidance on 2018, but it's reasonable to expect that we will return more to traditional spend levels on the infrastructure side of things in 2018.

And then also on the delineation, we talk about that a lot internally, how much delineation do you want to do in 2017, how much do you want to do in the future. And every time we have that conversation, we always end up back to the point that let's drill the highest rate of return wells first.

And like I talked about in my prepared comments, we've got a bunch of really, really attractive Wolfcamp A wells in our future.

And there will be some cases where for lease provisions and other requirements that we have to drill in other zones, but I think the vast majority of our CapEx over the next several years will be focused on drilling our highest rate of return wells.

The think the only thing that would change that is that if through our own selected testing or offset industry data finds a zone that actually generates a higher rate of return, then we'll continue to just focus on Wolfcamp A..

And, Travis, that comment right there was going to lead to my second question, as far as you were going to add a rig obviously down at the Brigham area once you take that over.

Are there things that could change the drilling plans for the end of the year as terms of – or the allocation of rigs based on the returns, or would that be more of an 2018 event with 2017 being pretty well set?.

Again, we're not providing a lot of color for 2018, but I've made a comment that we can get up to 10 rigs, and I think if that's the case, you're going to have five or six in the Midland Basin side and five or six on the Delaware Basin side.

So we believe that the returns to our shareholders are about equivalent on either side of the basin based on the wells that we're drilling. So we intend, as a go-forward basis, to have equal allocation across both basins.

As a matter fact, organizationally, we're trying to separate the organization out into more of a Delaware-focused organization and a Midland Basin organization. And each will compete for allocation dollars..

Great. Great. Thanks, Travis, for the details. Take care..

Thank you. Our next question comes from the line of Drew Venker from Morgan Stanley. Your line is open..

Hi, everyone. Travis I was hoping you could just go back to the comment you made in your prepared remarks about growing at peer-leading rates within cash flow. I think it is somewhat of a different path than what you guys have followed historically.

Can you talk about what has changed the appetite to spend? And I guess how that might change at higher prices?.

Well, I think the right way to think about our spending is to – as prices increase, we generate free cash flow. I think it's reasonable to increase drilling activity and we'll pick another rig up, and we'll use that cash flow appropriately that way in drilling wells.

And then it's also important to remind everyone that part of our genetic code, part of our DNA is to always remain opportunistic in acquisitions, big or small. In fact, if you just want to look at our balance sheet, I think that gives you an idea of how we maintain that flexibility.

So the world of outspending cash flow and levering up your balance sheet is just – if 2014, 2015 proved anything to the industry yet again it's that you better take care of your balance sheet or you're going to lose control of the things that you want to control to develop your assets.

So we're just going to be very conservative as we go forward in the future on what we do to the balance sheet, but we'll remain opportunistic..

Thanks for that, Travis. And following up on your comments on M&A, obviously, we continue to expect you to be in the marketplace.

But is there much that you see out there today that looks attractive or that would fit naturally with your existing asset base?.

Like I said, on the bolt-on stuff, there's little smaller deals, we continue to have very active conversations on ways to do that that allows us to apply our efficiencies in a more meaningful way, bolt-ons, smaller trades.

I think in terms of the big deals, I think we're probably on the backside of that curve, but I'm not aware of every deal that's out there. We know that we were very active over the last 18 months, both as Diamondback and as an industry, particularly in the Delaware Basin.

And I think we'll see how that goes, but I believe we're definitely on the backside of the number of trades that are going to be happening..

I appreciate the color. Thanks..

Thanks, Drew..

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

Thanks. Good morning, everybody. Travis, I just wanted to get back to your comment on the shift towards execution and appreciate what you said as far as how that impacts your M&A strategy.

But just wanted to get a sense on, if anything, if that changes how you view your development strategy and the assets currently in hand, either through spacing, completion designs, or stacked bench drilling, any type of configuration changes we might be seeing as you kind of look to execute going forward..

Yeah, all of those things, Gordon, are things that we test internally. We've tested them in the back-half of 2015 and then through all of 2016. We tend to be more conservative in the communication of the results, and we're conservative in the number of locations that we talk about under our asset base.

Rather than try to convince you in a PowerPoint presentation in our investor deck that we have a lot of locations, we try to underpin those decisions based on the testing. And that testing has to generate a greater return than what we'd do on a standalone basis. So Mike mentioned our continued completion optimization being a rate of return focused.

That's the way we think about all of the issues that you just outlined. It has to generate an incremental NPV, and it has to generate a greater rate of return for our investors. If it does, we do so. If it doesn't, we'll let other people do that. So it's all part of the way that we think about converting rock into cash flow.

We want to do that as efficiently as we can, and I think so far our track record looks pretty good..

Okay. That's it for me. Thank you..

Yeah, and Gordon, one other thing on that is we've talked about our shift to resource execution. That's not to imply that we haven't always been focused on resource execution.

In fact, if you look at the metrics that we care about whether it's time to TD or our cash operating cost and our cash margins per barrel, all of those are indicative of how we have been very focused on executing where our existing asset basis is.

I think one of the best measures that kind of separate a lot of companies is if you look at just your proved developed F&D cost because you've got audited numbers in the numerator and audited numbers in the denominator. And that's a good measure of efficiency of a company, we believe.

And I think if you look at Diamondback's number of $7.26, I think we'll stand up pretty good under that scrutiny..

Thanks, Travis..

Thank you. Our next question comes from the line of Sam Burwell from Canaccord. Your line is open..

Good morning, guys. I wanted to clarify one thing on kind of the upper bound of your guidance both on the number of completions and the 76,000 to date.

Does that factor in 10 rigs in the back half of 2017, or is that really just the eight-rig base case kind of...?.

Yeah, that's more the eight-rig base case. If you think about the ninth or tenth rig we've talked about, if they come it'll be certainly back half weighted, likely in the fourth quarter, certainly for the tenth rig. So you won't have any current year impact to speak of for either the eighth or the ninth rig – I'm sorry, the ninth or the tenth rig..

Yeah, all right. That makes us.

And I think this was touched on before, but those two incremental rigs would likely go to Delaware?.

Yeah, we're still balancing that, but likely, that's the case. We just need to make sure. We've got to take over operations, and so take over operations of the Southern Delaware block we bought from Brigham, and we'll do that until March 1. So we'll make that decision in the upcoming quarters..

Okay.

And then the final one would be how do you guys see your corporate oil cut developing over the next year or two now that you're just kind of layering in some Delaware production? Do you expect it to stay pretty much the same or to trend up a little bit?.

Yes. When we bought the acquisition, one of the things that we got quite a bit of surprise from our investors was the fact that there wasn't a great deal of understanding of where the highest oil cut was in the Delaware Basin, the Southern Delaware.

And in fact the Brigham assets is located in areas that have the highest oil cut and on the whole Southern Delaware. So when you think of Diamondback on a standalone basis, pre-acquisition, we kind of had a 73% to 75% oil cut. As we begin to aggressively develop our assets in the Southern Delaware, our oil cut actually goes up probably to 78% to 80%..

Sounds good. Congrats on a great quarter, guys..

Thanks..

Our next question comes from the line of Tim Rezvan from Mizuho. Your line is open..

Hi. Good morning, folks. Thanks for taking my call. You all have been a little less outspoken than some peers on the focus operationally on high-intensity fracs. I was wondering if you could talk about how widespread that implementation is. I know you talked about it in Andrews County.

And maybe if you can discuss how that changes the use of artificial lift and what it's doing for your curves?.

Hey, Tim, this is Mike. On the Midland Basin side, the high-density near-wellbore fracs are a standard completion design across all of our areas. As far as what they do from an artificial lift standpoint, the total amount of fluid coming out of the well is still fairly similar to what we had before.

So as far as artificial lift, the standard ESPs or gas lift that we typically use are about the same. What we have seen, and I think you'll see in some of the slides, are some of the declines are muted a little bit, so we have the ESPs on a little longer than we may have had in the past before we changed over to rod pump..

Okay.

And then I guess you have to drill before you have an idea on the Delaware, but do you have any initial thoughts on – will the high intensity be the standard? Or do you plan to walk up your completion design there?.

So the Southern Delaware is a little farther along and it's been kind of a very accelerated pace of change for the Delaware, but it went from just a 200 pounds per foot to know upwards to 2,500 pounds per foot to 2,000 pounds per foot. So when we go over there, that is similar to what we're doing now in the Midland Basin side.

So we'll have a very similar program when we start completing wells through Diamondback on the Brigham asset as well as the Luxe asset. So the answer is yes. It will basically be the same. It will have a slightly higher amount of stimulation fluid per foot and sand per foot than we do on the Midland Basin side, but comparable..

Okay. That's all I had. Thank you..

Thank you. Our next question comes from the line of Michael Hall from Heikkinen Energy Advisors. Your line is open..

Thanks. Congrats on a strong end to 2016. Just curious, we've heard a lot of commentary from other producers about pretty back-weighted production profiles over the course of 2017.

I'm just curious if you'd be willing to provide any expectations or color as to how the 4Q 2017 looks relative to, I don't know, maybe on a year-over-year basis, or just how steep or how linear the production profile might look over the course of 2017?.

Yeah, Michael, we've always stayed away from quarterly guidance. There's so much uncertainty in the way that we bring these wells on with these multi-well pads, and then you have the water-out effect.

And so if we get into quarter guidance, then there's some quarters they get out in front of us and some quarters because of the operations and water-out effects we had they kind of get behind us. So I think in a general sense, you're going to have a pretty smooth progression of volumes.

But that being said though, we've got to get out there and execute and we know we'll see interruptions in productions as we progress the volume growth through the year..

Fair enough. Appreciate it. I figured it was worth the shot. And then I wanted to talk a little bit more about just your thoughts on spacing. Mike, you highlighted in the deck, you do have a more conservative view on spacing than some of the peers or your peers out there.

I'm just curious how you guys think about the risks of I guess leaving resource behind in that context and just where your current thoughts are on under versus over-capitalizing the acreage and how you play that risk?.

Yeah, generally, in each of our areas, we're still in testing mode right now. One thing we have seen is from what we call our high-density near-wellbore fracs based on our microseismic monitoring, we're seeing some good results from that and that we are keeping the frac near-wellbore that gives us some hope that tighter well spacing will work.

So we're testing that pretty much in each of our areas now. Midland County is probably the furthest along, and we've got several multi-well pads that we've just brought on to test that concept. So over the next several quarters, I think we'll have a lot better idea than we do right now.

But I'll play some of the early results do provide some hope, but each area is different..

What's sort of the tightest spacing configuration that you guys are currently testing in those pilots?.

Yeah, I mean the tightest we're doing is essentially 500-foot spacing with staggered landing zones in the Lower Spraberry in Midland County. We've got some working interest in some other operator wells that are testing, kind of, 500-foot spacing in some of the Wolfcamp zones that we're monitoring.

So that's essentially the tightest that we've done to this point..

Okay. That's helpful. And then I just wanted to maybe step back, look longer term. You guys provided a comment in the Brigham slide deck at that time that you thought the assets now could support 15 to 20 rigs.

I think in the past you talked about the potential for, call it, two rigs per 10,000 acres or so which would suggest quite a bit more than that 15 to 20 rig comment.

Care to maybe talk about how we bridge that gap? Or what sort of upside there might be to that 15 to 20-rig potential over time as you move deeper into development mode?.

Sure. The comment that we made at acquisition time was 15 to 20 rigs, but that encompassed both asset sides..

Sure..

The Midland Basin side and the Delaware Basin side and we have made the comments that roughly 10,000 acres is a good – two rigs per 10,000 acres is a good mantra.

What we're trying to do is we look at that ramp to 20 rigs in the future and trying to manage the efficiencies that we need to really convert that rock into cash flow and to the extent that commodity price and service cost allow us to generate that free cash flow, we can continue to increase rigs accordingly.

But we've got ways to go before we get there..

Sure..

So, right now, we're building an organization now to handle that 15 to 20 rigs..

Okay.

And in that context then, how are you on people for 2017 and as you ramp towards 2018, do you have a lot of hiring to be done as you bring on particularly this Brigham asset? And maybe just an update on your people?.

Sure. I believe within the last year, we had about 160 employees for an enterprise value company of around $11 billion or $12 billion.

We recognize that in order to execute the way we want to continue to execute in the future, we're going to have to add some very achievement oriented, very best at their craft individuals and we're in the process of doing that right now.

And I'm pleased with the applicant flow that we've had that's going to allow us to do just that, find the exceptional contributors that are going to continue to propel Diamondback forward in the future..

Very good. I appreciate it..

Thanks, Michael..

You bet..

Our next question comes from the line of Mike Kelly from Seaport Global Securities. Your line is open..

Hey, guys. Good morning..

Good Morning Mike..

My buddy, Michael Hall, just stole all five of my questions there. But there's one that I've been interested on. I've heard rumblings of the formation of a third kind of snake-based entity out of you guys that's focused on the midstream side of things.

And Travis, maybe, I was hoping you could expand on this raptor entity that may or may not really be in the works right now? Thanks..

Hey, Mike. This is Kaes. Really, it's just we see value in midstream, and when we entered the Southern Delaware, we had two blank space assets that we could build out gathering systems on.

I think we put a slide in there describing our existing Spanish Trail oil gathering assets, and we want to build on that by building oil gathering in, on the Brigham asset as well as the other Southern Delaware asset we purchased last year. So, we see a value proposition in midstream.

For the purposes of the near-term, it's just to maximize realizations. But we've seen some successful deals via our peers and their midstream assets, and I think we're of the size today that we're going to be spending money on infrastructure and might as well get a good return out of it for the long-term..

Got it.

Now do you see that as an opportunity to maybe get more aggressive on the spending there? I know you kind of highlighted that there's some one-time infrastructure CapEx going into this year, but can we see that maybe, Travis, get more aggressive on that front in 2018 and beyond? Or is this ultimately spun into an MLP, sold? And any kind of higher-level strategic thoughts of where you want to go with it?.

Yeah, I mean, we'd like to control everything on our lease that we have 100% utilization.

So if we have 100% utilization, we're going to drill with saltwater disposal wells, we're going to have the water transfer systems, we're going to have the oil gathering, in some cases, even gas gathering, and we're in for value creation and value maximization no matter what.

So whether that's a public entity or sale or just holding it, we'll look at all options..

Okay. Fair enough. Thanks a lot, guys. Great quarter..

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

Good morning, Travis. Just had one more question. You talked a lot obviously about M&A, and you've been active in that market.

But as you look at the position and even referencing slide 4 from the presentation, outside of those six core areas, just kind of what are the plans for those pieces of acreage and how you see those kind of fitting in the portfolio going forward? Is that just further down the line? Or is there potential trades and divestitures; things of that nature?.

Yeah, it's all of the above. It could be further down the line, it could be a trade, it could be a divestiture. And again, we're just focused on the maximum value creation that we have.

So we believe that the assets that are outside those circles on that map still have tremendous value, and we want to see whether that value is best for our shareholders or if we can monetize them and create even more value through our shareholders. So all of those equations are open right now.

Again, our focus right now is to get the acquisition in the Delaware closed and then get our execution machine cranked up in the Southern Delaware side of things..

Great. Thanks, Travis. I'll turn it back..

Thank you. Our next question comes from the line of Jeff Grampp from Northland Capital Markets. Your line is open..

Good morning, guys. Question on potential acceleration, Travis, talking about going from 8 rigs to maybe 10 rigs at some point this year, and it sounds like it's mostly dependent on commodity prices.

Is any of that dependent on infrastructure buildout in the Delaware? Or do you guys feel pretty good about where things are and potentially adding a couple more rigs there in 2017?.

Yeah, no, of course it depends on infrastructure build-out, and that's why we're getting started on it even before we close the acquisition. We're not going to accelerate activity if we can't convert that immediately into cash flow. That being said though, we've always talked about the Midland Basin side of our asset base can handle up to 10 rigs.

So if there's a scenario where we want to accelerate the inventory, we're not ready for whatever reason on the Delaware Basin side, we have plenty of capacity on the Midland Basin side to be able to do that..

Okay. Got it.

And just on the kind of smaller bolt-ons or kind of netting up your working interest on the Delaware side, do you guys feel that that's largely, I guess for lack of a better term, kind of tapped-out? Or do you still see some opportunities, I guess more specifically, with the Luxe asset in ramping that working interest higher?.

No, I'm real proud of our, particularly our land organization since we closed that Luxe acquisition. I think we took, as I said in Mike's prepared remarks, it went from 49% at the acquisition time, now we're up to 73%. That's really a good job by our land organization, a lot of heavy lifting. We're going to continue to do that. That's what we do.

That's part of our core competency. We believe that we should try to own 100% of the working interest of every well that we drill, and we're going to continue to do that. So no, Jeff, I wouldn't say that that effort is done with..

Okay. Great. Appreciate the time, guys..

Thank you. Our next question comes from the line of Dan McSpirit from BMO Capital Markets. Your line is open..

Hey. Thank you, and good morning, folks. Just want to follow-up on your comments about full cycle returns. That's a measure you seldom hear about in the oil and gas business.

How does that measure dictate what you would pay for leasehold? That is, is there a maximum price you would pay in an acquisition as measured on a per location basis? At what price doesn't it make sense to acquire leasehold? And what do you see as your full cycle returns on the Brigham assets? Thank you..

Yeah, those are all good questions, Dan. Obviously we're not going to get into a lot of details on how we look internally on what we'll pay for acquisitions. I do know that the higher per acreage cost – and we steer clear of location camps because I think there's some liberties in the number of locations that typically get communicated.

So we just look at on acreage count, the dollar per acreage count, and we run our full cycle returns against that. And the greater you pay on a dollar per acre basis, the lower your corporate returns are going to be. So it's just one of those things we continue to look at.

On every deal that we do we look at the full cycle returns, and that's how we make our decisions..

Got it. Much appreciated. Have a great day. Thank you..

Thanks, Dan..

Thank you. I'm seeing no other questioners in the queue at this time so I'd like to turn the call back over to Travis Stice, CEO, for closing remarks..

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

Ladies and gentlemen, thank you again for your participation in today's conference call. This now concludes the program, and you may now disconnect at this time. Everyone, have a great day..