Diamondback Energy Inc (FANG) 2016 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Diamondback Energy's fourth-quarter 2016 earnings conference call.

(Operator Instructions)

As a reminder, this conference call is being recorded. I would now like to reduce 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 the Diamondback's website. Representing Diamondback today are Travis Stice, CEO; Mike Hollis, COO; and Tracy Dick, CFO.

During this conference call the participants may make certain forward-looking statements relating to the Company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the Company's filings with the SEC.

In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.

As a reminder, Viper Energy Partners, a subsidiary of Diamondback, will be hosting its first standalone conference call at 10 AM central today. Dial-in details can be found on Viper's 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'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 differing 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 of the second acquisition, the $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 continuous 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 operations 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 operating recount to 10 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 developing cost 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 a barrel. Our 2017 LOE guidance at the midpoint is 9% 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're 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 will 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 our 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 but we believe we have 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 -- excuse me, the Reed pad, have well exceeded the performance of our first. Diamondback continues to maintain a rate of return focus completion optimization program.

On the Reed pad, we optimize well placement within the reservoir and utilized a stack and stagger approach while monitoring with microseismic. We also applied high-density near wellbore stimulations, including the use of diverting agent. 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, giving 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 have also completed our second and third Lower Spraberry wells. 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 and minerals. Our optimized simulation has become our standard design for the four proven zones in Midland County.

Slides 11 through 15 described 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 the majority of 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 both our acquisitions.

Our Brigham asset -- 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 rates in the future.

Turning to operations and execution, slide 17 demonstrates our continued track record of execution as DC&E cost are down 41% from 2014 while our average completed lateraling 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 purchase.

Slide 19 reflects our spacing assumptions relative to our peers, leaving considerable upside from down-spacing 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 have recently reduced our 2017 LOE guidance range to $4.75 to $5.75 per BOE compared to $5.50 to $6.50 -- I am sorry, $5.50 to $6 per BOE 2016 and that's due to improved pumping practices, lower well failure rates and increased horizontal production.

With these comments now complete, I will 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 non-cash 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, or the $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 completion, $10 million 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 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 6 to 10 rig program with 130 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 break even cash flow. We will also be spending $75 million on one-time infrastructure projects in the Delaware Basin. Investments, which are standalone basis, have returned that rival our operated wells while maintaining best-in-class operating margin.

I will now to 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 accelerate 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.

(Operator Instructions)

John Nelson, Goldman Sachs.

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

Thank you, John.

Travis, we are adding a lot of Permian rigs here each week. And a lot of investors obviously focused on oil field service cost inflation. You know you mentioned -- the team mentioned a lot of times in their prepared remarks you are baking in some level of service cost inflation of 2017 budget. Wondering if we can get kind of any further quantification of what that is that baked in. And then maybe you could also tie that in with what you guys actually seeing realtime and have we really seen the pressure start to build yet?

That's a good question, John. Just mathematically we have dialed in between a 10% and 15% total well cost increase starting in the first quarter. We are not seeing that just yet. We actually believe that if oil stays 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 will see these service cost increases start to accelerate in the back half of this year.

Now it is not that Diamondback is going to acquiesce on these cost increases. We are working diligently with our service providers and our business partners, like Mike had highlighted, to try to mitigate those costs. But we know that for a healthy industry, as we continue to build rigs in the Permian, we're going to have to have a service company that is well capitalized and ready to support increasing activity. I think last week here in the Permian we eclipsed 300 rigs and we are adding anywhere between five and 10 rigs per week.

And so if that pace continues, you will start to see some tightening. So we have not just opened our eyes to this phenomenon this quarter, it is something we have been doing really since the back half of last year when all activity increased. And while we may not be insulated from all service costs increases, we feel like we've been proactive enough to be able to offset some of the service cost that increases that we're forecasting. So really 10% to 15% on the total well costs, the drilling side -- we are not anticipating really much if any increase on the drilling site.

All of that increase is really housed on the completion side primarily under pressure pumping, which means we have 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 the services continues to increase to expect cost increases.

That's really, really helpful. My second question maybe 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, your team's been 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 the messaging, is it A, Diamondback has the scale and we're just indigestion mode for the time being? Or is it B, Diamondback has the scale but will continue to look at every deal that is in the market should there potentially be more over the course of 2017.

Yes. Good question, John. And let me get to that. I just want to close the other comment on the service cost increases. We have spent a lot of the last two quarters talking about savings that we have made permanent insight Diamondback Energy. So with the efficiency gains and things that we have done institutionally and organizationally in-house, we believe that also further insulates us from future cash, future cost increases.

So we have 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 it is needed. But do not forget that Diamondback has really led the away in pushing these savings and efficiency gains to make things permanent.

If you read our press release, we have 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 1,000 feet a day and now we are 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, yes, it is 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 are very comfortable with our inventory. And it is now all about resource execution. That being said though, we are 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, 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 will really focus on is on every quarter doing these bolt-on acquisitions that allows us to, like you pointed out, be more efficient than the seller and then also drill longer laterals or perhaps have addressed the service shortage potential more adequately than the seller. So we are still in the game. I have said all along that you're either in the game or out of the gate. And we're still in the game.

Great. I will let somebody else hop on. Congrats, again.

Thanks, John

Thank you. Pearce Hammond, Simmons.

Good morning and thanks for taking my questions. Travis, just following up on the questions just now on service cost, if they did accelerate maybe faster than what you are 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 do not think that is reasonable. I think you'd have to see a combination of rapidly increasing service costs coupled with a declining commodity price. I think that is the only time we would really start having that conversation again.

You have heard me talk about dead capital or standard capital. That is not a good thing for our investors and that is what DUCs are. They are at least deferred capital. And so as long as the industry moves in lock step with an increasing commodity price, I do not think it is 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?

Pearce, we take over operations here in a couple of weeks. But we have 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 these issues with the multi-rig drilling program. And I will give a shout out to the Brigham Resources operations team.

They have 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 are very proactive at. We have 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 are talking about.

Thanks, Travis. And congrats on a great 2016.

Thank you, Pearce.

Thank you. Neal Dingmann, SunTrust.

Good morning, Travis. Travis, from that question is a little bit on John's on overall spend. I know you have not and I'm certainly not going to hold you to any type as far as 2018 yet, but you mentioned about spending $75 million in the Delaware infrastructure. And then when I look at the upstream activity -- I guess what I am 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 than perhaps having more delineation or developmental-type drilling? So I guess I'm getting more bang for your buck, if you will, next year -- if you can comment on that.

Neal, we certainly see a value proposition on the midstream side of things. And as we pointed out in our prepared comments, there is 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 are right, we have not provided any guidance on 2018. But it is 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 have got a bunch of really, really attractive Wolfcamp A wells in our future.

And there will be some cases where for lease provisions 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. I think the only thing that will 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 will focus on it and we will continue to just focus on the 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 to the Brigham area once we take that over. Are there things that can change the drilling plans for the end of the year in terms of or the allocation of rigs based on the returns or does -- would that be more of a 2018 event with 2017 being pretty well set?

Again, we are not providing a lot of color for 2018. But I made the comment that we could get up to 10 rigs. And I think if that is the case, you are 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 equipment on either side of the basin based on the wells that we are drilling. So we intend, as a go forward basis, to have equal allocation across both basins. As a matter of fact, organizationally, we are kind of separating the organization up into more of a Delaware-focused organization and a Midland Basin organization and each will compete for an allocation of dollars.

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

Thank you. Drew Venker, Morgan Stanley.

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. This, I think, is a somewhat of a different path than what you guys have followed historically. Can you talk about what has changed appetite to spend and 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 is reasonable to increase drilling activity and we will pick another rig up and we will use that cash flow appropriately that way in drilling wells. And then it is also important to remind everyone that part of our genetic code, part of our DNA is to always remain opportunistic on acquisitions, bigger or small.

And 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 out spending 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 asset. 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 will remain we will 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 is -- would fit naturally with your existing asset base?

There's, like I said, on the bolt-on stuff, those little smaller deals, we continue to have very active conversations on ways to do that allows us to apply our efficiencies in a more meaningful way -- bolt-on, smaller trades. I think in terms of the big deals, I think we are probably on the backside of that curve.

But I am not aware of every deal that is 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 will see how that goes. But I believe we are definitely on the backside of the number of trades that are going to be happening.

I appreciate the color. Thanks.

Thanks, Drew.

Thank you. Gordon Douthat, Wells Fargo.

Thanks. Good morning, everybody. Travis, I just wanted to get back with -- 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 change how you view your development strategy of the assets currently in hand either through spacing, completion designs, or stack bench drilling -- any type of configuration changes we might be seeing as you kind of look to execute going forward?

Yes. All of those things, Gordon, are things that we test internally. We have 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 are conservative in the number of locations that we talk about under our asset base.

Rather than trying to convince you in a PowerPoint presentation on our Investor deck that we have a whole bunch -- a lot of locations, we try to underpin those decisions based on the testing. At that testing has to generate a greater return than what we do on a standalone basis. So Mike mentioned our continued completion optimization being rate of return focused. That is the way we think about all of the issues that you just outlined.

It has to generate an incremental MPV and has generate a greater rate of return for investors. If it does, we do so. If it does not, 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.

Yes. And just, Gordon, one other thing on that is, we have talked about our shift to resource execution. That is not to imply that we have not been always focused on resource execution. In fact, if you look at the metrics that we care about, whether it is 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 base 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 will stand up pretty good under that scrutiny.

Thanks, Travis.

Thank you. Sam Burwell, Canaccord.

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?

Yes. That is more than eight rig base case. I mean if you think about a -- the ninth or 10th that we've talked about, if it comes -- if they come, it will be certainly back half weighted likely in the fourth quarter, certainly for the 10th rig. So you will not have any current year impact to speak of for either of the eighth or the ninth rig. I am sorry, the ninth or the 10th rig.

Yes. Okay. That makes sense. And I think this was touched on before but those two incremental rigs would likely go to Delaware?

Yes. We are still balancing that but likely that is the case. We just need to make sure -- I mean we've got to take over operations and so take over operations of the southern Delaware block we bought from Brigham and we don't do that until March 1. So we will make that decision in the upcoming quarters.

Okay. And then the final one would be how do you guys see your corporate oil cut devolving over the next year or two now that you are 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?

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 was in the Delaware Basin -- the southern Delaware. And in fact the Brigham assets is located in areas that have the highest oil cut in on the whole southern Delaware. So when you think of Diamondback on the 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 the great quarter, guys.

Thanks.

Tim Rezvan, Mizuho.

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 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 is doing for your curves.

Hi, Tim. This is Mike. On the Midland Basin side the high-density near wellbore fracs our 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 ESP's 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 ESP's 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 in the -- and it has been kind of a very accelerated pace of change for the Delaware, but went from just 200 pounds per foot and now upwards to 2,500 to 2,000. So when we go over there, that is similar to what we are doing now in Midland Basin side. So we will have a very similar program when we go to that, when we start completing wells through Diamondback on the Brigham asset as well as the Luxe asset.

So the answer is yes. It would basically be the same. It will have a slightly higher amount of stimulation fluid per foot and sand per foot than we do in the Midland Basin side, but comparable.

Okay. That's all I had. Thank you

Thank you. Michael Hall, Heikkinen Energy Advisors.

Thanks. Congrats on a strong end to 2016. Just curious, we have heard a lot of commentary from other producers about pretty back-weighted production profiles over the course of 2017. Just curious if you would be willing to provide any expectations or color as to kind of how the 4Q 2017 looks relative to maybe on a year-on-year basis, or just how puff steep or how your linear production profile might look over the course of 2017.

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 affect. And so if we get into quarterly guidance, then there is some quarters that get out in front of us and some quarters because of the operations and water out effects we had kind of get behind.

So I think in a general sense, you're going to have a pretty smooth progression of volumes. But that being said though, we have got to get out there and execute. And we know we will see interruptions in production as we progress the volume growth through the year.

Fair enough. Appreciate it. I figured it was worth a shot.

And then I want to talk a little bit more about your thoughts on spacing. Like you highlighted in the deck, you do have a kind of 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 leaving resource behind in that context and just where you your current thoughts are on under versus over capitalizing the acreage and how you play that risk.

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 are 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 are 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 have just brought on to test the concept. So over the next several quarters I think we will have a lot better ideas than we do right now. But I will play some of that early results do provide some hope. But each area is different.

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

The tightest we are doing is essentially 500 foot spacing with staggered landing zones in the lower Spraberry in Midland County. We have got some working interest in some other operators' 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 have 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've 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 rate comment. Care to maybe talk about how we bridge that gap or what upside there might be to that 15 to 20 rig potential overtime as you move deeper into development in that?

Sure. The comment that we made at acquisition time was 50 to 20 rigs, but that encompassed both asset sides; the (multiple speakers) Basin side and the Delaware Basin side. And we have made the commented that roughly 10,000 acres is a good -- two rigs per 10,000 acres is a good mantra. What we are trying to do is we look at that ramp to 20 rigs in the future and trying to manage the efficiency that we need to really convert that rock into cash flow.

And to the extent that commodity price and service cost allows us to generate that free cash flow, we can continue to increase rigs accordingly. But we got a ways to go before we get there. So right now we are building an organization out to handle that 15 to 20 rigs.

Okay. And then in the context, how are you on people for 2017? And as you ramp towards 2018, do 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. We had -- I believe at the end of 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 are in the process of doing that right now. And I am pleased with the applicant flow that we have had that is 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. Appreciate it.

Thanks, Michael.

You bet.

Mike Kelly, Seaport Global Securities.

Good morning. My buddy Michael Hall just stole all five of my questions there. But there is one that I have been interested on. I have heard rumblings of the formation of a third kind of snake-based entity out of you guys that is 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.

Mike, this is [Case]. Really it's just we see value in midstream and when we entered the southern Delaware we had to 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 asset and we to build on that by building the oil gathering in -- on the Brigham asset as well as the southern Delaware asset we purchased last year.

So we see a value proposition in midstream for the purposes of the near-term. It is just to maximize realizations. But we have seen some successful deals be our peers and their midstream assets. And I think we are 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.

Okay. Do you see that as an opportunity to maybe get more aggressive on the spending there? I know you kind of highlighted that there is 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? And is this ultimately spun into an MLP sold? Any kind of higher-level strategic thoughts of where you want to go with it?

Yes. We would like to control everything on our lease that we have 100% utilization. So if we have 100% utilization, we're going to drill with salt water swells of wells. We're going to have the water transfer systems. We're going to have the oil gathering and in some cases even gas gathering. And we are in for value creation, value maximization no matter what. So whether that is a public entity or sale or just holding it, we will look at all options.

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

Thank you. Jason Wangler, Wunderlich.

Good morning, Travis. Just had one more question talking a lot obviously about M&A and you have been active in the market. But as you look at the position and even referencing slide 4 from the presentation, outside of those six core areas, 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?

Yes. It is 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 went to see if whether that value is best for our shareholders or if we can monetize them and create even more value for our shareholders. So all of those equations are open right now. Again, our focus right now is to get the acquisition on Delaware closed and then get our execution machine cranked up in the southern Delaware side of things.

Great. Thanks, Travis. I will turn it back.

Thank you. Jeff Grampp, Northland Capital Markets.

Good morning, guys. Question on potential acceleration, Travis, talking about going from eight to maybe 10 rigs at some point this year. And it sounds like it is mostly dependent on commodity prices. Is any of that dependent on infrastructure build out in the Delaware? Or do you guys feel pretty good about where things are and potentially adding a couple more rigs there in 2017?

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 are 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 we won't accelerate the inventory, we are 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 netting after working interest on the Delaware side, do you guys feel that is largely, for lack of a better term, kind of tapped out? Or do you still see some opportunities more specifically with the Luxe asset and ramping networking interest higher?

No. I am real proud of our particular land organization since we have closed that Luxe acquisition. I think we took, as we said, in my Mike's prepared remarks went from 49% at acquisition time. Now we're up to 73%. That is really a good job by our land organization. There's a lot of heavy lifting. We are going to continue to that. That is what we do. That as part of our core competency. We believe that we should own -- we should try to own 100% of the working interest of every well that we drill. And we are going to continue to that. So, no, Jeff, I would not say that effort is done with.

Okay. Great. Appreciate the time, Jeff.

Thank you. Dan McSpirit, BMO Capital Markets.

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 require a leasehold? And what do you see as your full cycle returns on the Brigham assets? Thank you.

Yes. Those are all good questions, Dan. Obviously we're not going to get into a lot of deals on how we look internally on what we will pay for acquisitions. I do know that the higher per acreage cost -- and we steered clear of location camps because I think there is some liberties in the number of locations that typically get communicated. So we just look at an acreage count, a dollar per acreage count and we run our full cycle of returns against that. And the higher you -- 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 decision.

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

Thanks, Dan.

Thank you. I'm seeing no the questioners in the queue at this time so I would 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.