Diamondback Energy Inc (FANG) 2017 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy Third Quarter 2017 Earnings Conference Call.

As a reminder, this conference is being recorded.

I would now like to introduce your host for today's conference, Adam Lawlis, Director, Investor Relations.

Sir, you may begin.

Thank you, Simon.

Good morning, and welcome to Diamondback Energy's Third Quarter 2017 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, President and 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 on the company's filings with the SEC.

In addition, we will make reference to certain non-GAAP measures.

The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.

I'll now turn the call over to Travis Stice.

Thank you, Adam.

Welcome, everyone, and thank you for listening to Diamondback's Third Quarter 2017 Conference Call.

Over the past 5 years as a publicly traded company, Diamondback has operated by 3 core principles: best-in-class execution, low-cost operations and transparency while concurrently maintaining strict capital discipline.

The third quarter was no different for Diamondback as we continued to deliver on each of these principles.

This foundation of our business strategy, along with our attractive acreage position and strong operations-focused organization, allows us to grow production differentially within cash flow at nearly any commodity price.

Capital discipline and operating within cash flow are not new concepts at Diamondback, as we have grown production by over 175% in the last 11 quarters within operating cash flow.

The company has never been about growth for growth's sake, and management is not rewarded for growth, but rather rewarded for capital efficiency and cost control.

We are operating 9 rigs today, 6 in the Midland Basin and 3 in the Southern Delaware Basin, as well as operating 4 dedicated completion crews.

We plan to add a 10th rig in the coming weeks and maintain this rig cadence until year-end, given current commodity prices.

As we look ahead into 2018, we will match operating cash flow to drilling and infrastructure CapEx and increase or decrease rig count accordingly, just like we have done historically.

As shown on Slide 6, Diamondback has had a consistent focus on corporate returns and full-cycle economics.

The industry commentary has pivoted recently, but Diamondback has always emphasized that returns matter as evidenced by generating an average return on capital employed of over 8% for each of the past 4 quarters and a peer-leading production per debt-adjusted share growth over 130% since the second quarter of 2014.

With these comments now complete, I'll now turn the call over to Mike.

Thank you, Travis.

Turning to Slide 8. Year-to-date, Diamondback has generated $84 million of free cash flow and has maintained capital discipline of operating near cash flow breakeven for 11 quarters.

Diamondback plans to maintain this level of capital discipline in the coming years, adding rigs as cash flow allows.

Slide 9 shows our average lateral length completed over time as well as the number of wells drilled and completed each quarter.

Diamondback continues to drill and complete wells as efficiently as possible, with 4 completion crews currently running across our asset base, and average lateral lengths completed up 20% quarter-over-quarter.

As shown on Slide 11, we have controlled well cost under $700 per completed lateral foot in the Midland Basin year-to-date while maintaining industry-leading cash margins of 80%.

We are continuing to work to mitigate service cost inflation by increasing efficiencies, drilling longer laterals across the basin and debundling services, particularly on the pressure pumping side of the business.

Turning ahead to Slide 14.

We have new data from multiple well results across our Southern Delaware Basin assets, including 2 90-day IPs that demonstrate the strong extended performance of wells in the area.

Our first operated Lower Second Bone Spring well continues to exceed expectations, and as a result, we are evaluating additional tests of this zone in 2018.

We are currently running 3 rigs in the Southern Delaware Basin and plan to have our new operated rig [shortly] after drilling its first pad in the Midland Basin.

We continue to maximize netbacks by building and upgrading infrastructure across the asset base.

Turning to the Midland Basin.

We are currently running 6 rigs and plan to maintain this cadence.

Slide 17 shows the continued impressive performance from our assets in Howard and Andrews County, with wells in both areas continuing to outperform reserve auditor type curves.

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

Thank you, Mike.

Diamondback's third quarter 2017 net income was $0.74 per diluted share, and our net income adjusted for noncash derivatives was $1.33 per diluted share.

Our adjusted EBITDA for the quarter was $232 million, up 6% quarter-over-quarter, with cash operating cost of $7.67 per BOE.

During the quarter, Diamondback spent $225 million on drilling, completion and nonoperated properties and $33 million on infrastructure.

Year-to-date, we have generated $84 million of free cash flow, excluding acquisitions.

As shown on Slide 19, Diamondback ended the third quarter of 2017 with a net debt to Q3 annualized adjusted EBITDA ratio of 1.4x and $791 million of pro forma liquidity.

In connection with our fall 2017 redetermination expected to close in November, the lead bank on our credit facility recommended a borrowing base increase to $1.8 billion from $1.5 billion.

The company will elect an increase in commitment to $1 billion from the current elected commitment of $750 million.

Additionally, Viper expects to have its borrowing base increased to $400 million from $315 million currently.

Our full year 2017 production guidance presented on Slide 20 was increased 3% from prior midpoint while narrowing CapEx guidance.

I'll now turn the call back over to Travis.

Thank you, Tracy.

Diamondback was able to deliver another great quarter as a result of our continued commitment to execution and low-cost operations.

We are increasing production guidance while maintaining capital spend and cash operating costs for the year.

As we look forward to 2018, our strategy has not changed in that we expect to match our capital budget to our projected operating cash flow and have the ability to differentially grow within cash flow for many years at nearly any commodity price.

Before we open the line for questions, I want to make one final comment.

This past October, Diamondback celebrated the 5-year anniversary of our IPO.

In these 5 years as a public company, we've grown from a couple of dozen employees to now over 250 and from a couple thousand barrels a day production to now over 85,000 barrels a day.

To our employees who were here in the early days, we'll always be indebted to your loyalty.

And to our employees who have joined us over the past years, we've successfully built an amazing company with a future that remains bright because of the collection of your individual talents, hard work, trust, determination and perseverance.

Thanks to each of you for what you've done.

Operator, please open the line for questions.

(Operator Instructions) Your first question comes from the line of Dave Kistler with Simmons/Piper Jaffray.

Real quickly, on Slide 4, you guys highlight how activity may move in different price regimes.

Can you talk a little bit about how you guys think about that when thinking about balancing growth and return on capital versus return of capital going forward?

In other words, is there a point at which you elect not to increase rig count within cash flow, but rather return cash flow to shareholders?

Yes, Dave.

That's a great question, one that we've modeled consistently going out into the future.

And I think the right way to think about it is, is we believe that the quickest way to generate that excess free cash flow is to get to a rig cadence of somewhere around 15 to probably 18 rigs.

And I think the right way to think about that is that any discretionary cash flow that's created, think about it being redeployed until we get to that rig cadence.

Once you get to that rig cadence, which we feel like is the maximum efficiency on our current acreage footprint, then we can have conversations about true return of capital.

But it's certainly something that, in the not-too-distant future, our model shows that we'll be able to have those conversations.

Great, I appreciate that color.

And then kind of looking at the second Bone Spring, and in your presentation, you kind of talk about, the existing plan has been 4 wells per section.

But that Kelley State well would maybe indicate that there's a possibility for prosecuting that interval with both an upper and a lower series of wells.

Can you talk a little bit about how you're thinking about that timing of kind of watching those wells, the extra work you're doing on that and when that might allow you guys to make a decision for adding incremental inventory?

Yes.

Dave, historically, we've not been part of the story about trying to add a ton of locations every quarter call and feed the NAV machine.

We've tried to be very conservative in the way that we communicate locations.

And we're doing a lot of science still on this pretty exciting horizon, but yet still one that we don't have a lot of data on.

So we're going to be drilling a well this year and before the year-end, and we'll look to have that well completed early next year.

And we'll be able to communicate more about how we view the development of that asset probably in our May-ish -- May time frame.

And I think it's important to remember that as we underwrote the Brigham acquisition, we put the majority of the value on the Wolfcamp A. So this is -- while it's not unrecognized, it's probably unrealized upside in our acquisition model that has us pretty excited.

And the reason for that is because it's a little shallower and it's a little -- it's still slightly overpressured, but it's a lot easier to drill.

And the cost, we believe, is going to mirror real closely to what we see on the Midland Basin side.

So it'll give us -- when we allocate capital, gives us a really good -- a new horizon.

But there's still some work left to be done, Dave.

Great.

I appreciate that.

One last one from me.

I noticed that Delaware well costs kind of crept up a little bit or at least the guidance on that crept up a little bit.

Can you talk about what you're doing differently there?

Or is that purely just a little bit of service cost inflation that's creeping in?

Dave, Kaes here.

We're trying a couple of things.

We went into the year new to the Delaware Basin, so came in with a pretty wide guide on well costs.

I will say, in the back half of this year, we've done a lot more 2,500 pound-per-foot jobs on the sand side versus 2,000 pounds per foot in the beginning of the year.

And with that comes extra fluid as well.

So extra fluid, extra sand and extra time on location on the completion side has really driven that cost up.

And I will say, our drilling guys continue to decrease days on location and increase cycle times on the drilling side.

So we've seen improvement there on the cost side, it's just -- trying a bigger spin as we figure out our mix going forward.

Your next question comes from the line of Neal Dingmann with SunTrust.

Travis, my first question, looking at Slide 5, I thought that was a good -- new slide that you all have out.

Could you talk about on that, just basically going through your assumed spacing assumptions there?

I mean, you certainly seem like -- much like other things you all do, you seem more conservative than others on a number of formations there.

I just -- any color you could add to either side as far as how you think about that today versus what we can maybe see in '18?

Yes, Neal, you've studied us now for 5 years, and you know that typically, we try to be conservative in the way we communicate things like the number of locations per section.

And what we like to do is add locations, not take them away.

And we like to have, when we add locations, not only the science done that proves it clearly in our own mind, but also in the minds of our reserve auditors.

And so I think you're going to continue to hear Diamondback conservatively talk about the number of locations.

Again, back to my comments about what we've done historically is not been trying to drive the NAV machine through location adds every quarter.

I think what we've done is generate really high returns on a full-cycle basis, and things that matter like return on capital employed and debt-adjusted cash flow per share, I think we stand and -- pretty unique in that inspection.

And then lastly, Travis, could you just talk just one on leasing, both a little bit on what you see on potential, you and Kaes, the team, on M&A and then if just any of your other locations you see -- you potentially might be writing off?

Yes, I mean, from a leasing perspective, we continue to actively bolt on and trade in all areas.

Each land team treats an area as their own little BD department, so we're excited with the small amount of deals we've done.

But they definitely increased lateral lengths and working interest in areas that, for instance in the ReWard area, we bought it at a 49% working interest and now we're up into the high 70s, so essentially bringing a half a rig of value forward.

On the larger M&A side, it's been tough to see a lot of Tier 1 properties available in 2017.

I think from our perspective, we're very focused on something -- buying something that's immediately accretive to one, cash flow per share; and two, our overall asset base.

And we really haven't seen that across the Permian in 2017.

Your next question comes from the line of John Nelson with Goldman Sachs.

Travis, I was wondering if you can comment just on maybe some of the layer tightness you are kind of or not seeing within the basin between yourselves and your service providers.

I know you've talked about kind of getting to a target of 15 to 18 rigs longer term being optimal.

Do you think the organization is already kind of staffed at those levels?

Have you -- where have we come from a staffing level kind of year-to-date?

And any sort of labor pass-throughs maybe you're seeing from some of your service providers?

Things along those lines, that would be helpful.

Sure.

I think, John, our industry has demonstrated in times past when commodity price starts to move, you start hearing your business partners on the service side starting to ask for rate increases so they can build their working capital.

And look, we want our business partners to be successful, we want them to continue to build new equipment and crew those -- that new equipment with qualified staff.

And so it's part of our business cycle, and we anticipate some increases this year as we've earlier guided.

I think our total well cost, we talked about an increase of 5% on the total well cost for the year.

And that was taking some of those comments under consideration.

When you look internally for Diamondback, I was mentioning' we're going to pick 10 rigs up.

We're very comfortably staffed for 10 rigs right now.

And as long as we build our rig fleet every 3 to 5 months as we generate enough free cash flow to cash flow that rig, we're not going to have internal constraints.

It's incumbent upon Diamondback's leadership team to always make sure we've got the right number of people to prosecute our plan.

At about this time last year, we had 100 and -- about 160 employees, and now we're up to a little over 250.

So we've gone through likely an unprecedented growth in our company's history, but we feel very comfortable where we sit today to be able to prosecute our plan with 10 rigs.

And we'll continue to find the best athletes in the draft, and we'll add those players accordingly.

That's really helpful.

And I guess my second question, again a little bit higher-level.

But just curious how much have -- has the internal kind of debate really bought into the recent strength in oil prices?

We appreciate the comments that will spend within cash flow in 2018, but I imagine your estimate of where that'll be now versus where it was in July has changed pretty materially.

So if you could just speak to how you will potentially protect to make sure that you spend within cash flow, whether it's additional hedging or just a wider guidance range for us.

But any thoughts on that would be helpful.

Sure.

I'll let Kaes here in a second talk about what our hedging strategy is and remind the audience.

But let me talk about, strategically, about how we think about commodity price as we've run our business out.

We've always used a conservative price.

Conservative to probably strip, and I think it does a couple of things for us organizationally.

When you run a lower commodity price, I believe it forces a discipline in the -- within the decision-makers and the asset teams as they allocate capital, because the lower commodity price focuses, I think, the organization on making sure we're doing everything at the highest rate of return.

And the second thing is, is if we miss on oil price because oil price is actually higher, well then we generate free cash flow.

And as I've talked about earlier, we know what we're going to do with free cash flow until we get to somewhere in that 15 to 18 rig count -- rig cadence on our existing acreage base.

And then I'll let Kaes answer, remind everybody what our strategy is on the (inaudible)

Yes, one other point, John.

We plan our business below strip, and right now, at current production on an annualized basis, every dollar priced gives us about $30 million of cash flow, so -- gives us a lot of protection on adding those rigs at the right time.

And then back to hedging, we continue to protect what we think is the minimum drilling required to maintain our leasehold across both basins.

And right now, on a 12-month-forward basis, that's probably a 5-rig cadence.

So we basically look at our swaps and multiply them by the oil price that we have protected.

And right now, average price is over $50, and -- look to protect about 5 rigs for the next 12 months.

Your next question comes from the line of Drew Venker with Morgan Stanley.

Travis, hoping you could just talk about how much of your capital allocation is driven by logistics and midstream considerations, versus just rates of return.

You had some really strong results across the whole portfolio in the Delaware this quarter, some really outstanding results, and it looks like the core legacy position for the Midland Basin performing very strong as well.

But just curious if there are -- you see material limitations there or really can you run as fast as you want across a lot of the areas you have.

Drew, yes, on the Midland Basin side, I'll divide it into the Midland and Delaware.

On the Midland Basin side, we can really run as fast as we need to now.

I think we were fortunate through the down cycle to build some infrastructure to be able to flow barrels on the freshwater side or the disposal side and make sure we can operate at a high rig cadence on the Midland Basin.

And on the Delaware, we've been running 3 rigs, we're -- our fourth rig is going to move out there sometime in early 2018.

We anticipate the major infrastructure items that we had budgeted this year to be complete by the end of Q1.

And then really, it's off to the races, and we can add rigs as we see fit on the Delaware side as well.

So a pretty high infrastructure spend for us this quarter and probably into next.

And then after that, we will return to a more standard infrastructure spend as a percentage of total capital.

Okay, that's helpful.

And just a follow-up to the plan for next year.

In the Delaware, you had some really strong results in [both the] Bone Spring in addition to the Wolfcamp A. Can you speak to what the delineation plans are for next year or how you plan to size up that resource over the next 12 months or so?

Yes, the majority of our capital will still be spent on the Wolfcamp A looking into next year.

On the Delaware side, we are very encouraged by the second Bone Spring, so you should see some tests in the first half of 2018.

I'd also anticipate some third Bone Spring results probably in the Reeves County area throughout the year and maybe a couple Wolfcamp B tests.

But the vast majority of our capital in the Delaware will be spent on the Wolfcamp A.

Your next question comes from the line of Asit Sen with Bank of America Merrill Lynch.

Travis, just a --2 broad questions for you.

Could you speak broadly as to -- how do you -- how you view the oil service market today?

In your view -- and this is not just FANG, but your view on how things change in a 55-plus dollar world.

Yes, Asit.

We can't really predict service constraints, but what we do expect, that we're going to be first in line in terms of the additional needs that we have with our business partners on that side.

As I mentioned before, we continue to see -- as commodity price goes up, we see that our business partners on the service side requesting, at some points, price increases.

But I think it's important to note that it hasn't been an impediment to our growth.

We've still been able to grow even with the increases in price.

Okay.

And since we have you on, Travis, I wanted to hear your thoughts on the industry debate on Permian production growth into 2018.

Could we be disappointed on that?

What are your views on that today?

Yes, there's a lot of really smart people that study total production coming out of the Permian.

I think past performance is a good indication of future -- what goes on in the future.

And I think if you just look at what's happened in 2017, particularly in 2Q and 3Q releases, I think you've seen some operators, not Diamondback, but you've seen some of the industry having trouble prosecuting their plan.

And if commodity price continues to rise and some of these constraints that people are talking about surface, then there's a possibility to probably surprise to the downside.

But again, there's a lot more intelligent people that study that, you know on a -- that macro view than Diamondback.

But what Diamondback focuses on is how we can accurately put a forecast together that grows our production in the future and with a high degree of confidence and can do so within cash flow.

All right.

And my last macro question, Travis, I promise I'll stop there, is your thoughts on broader M&A in the Permian.

Yes.

I think Kaes commented on that a little bit earlier as well.

There's just -- you're just not seeing a lot of what we call Tier 1 properties in the marketplace, and Diamondback is very confident that we can grow for many years in the future with what our current inventory is, although I do have a responsibility from a business development perspective to continue to look for deals that were going to be accretive to our shareholders.

And I've said in the past that our fingerprints should be on every trade that occurs out in the Permian Basin, and I think you're either in that game of business development or you're not.

And we continue to be active in looking for opportunities.

But with the high-quality inventory that we have, we don't feel necessarily compelled to do something unless it's really a great return for our shareholders.

Your next question comes from the line of Gail Nicholson with KLR Group.

Can you talk about how important landing zone is in regards to well performance?

And in regards to the higher -- high-resolution 3D seismic shoot that you guys are doing [that you'll get] in '18, do you think that'll help better land wells to improve well performance?

Or do you think that's more in regards to maybe proving up some maybe incremental zone potential across the Delaware Basin?

Yes, Gail.

I'll probably let Paul answer the specifics about the 3D -- the high-res 3D seismic, but let me just give you a broad view of how we think about it, the landing zone.

In the Midland Basin, where we've got close to 300 wells drilled now, we feel very confident at the right landing zone and we have for quite some time.

And we've very efficiently geosteered within probably a 20-foot window, and we're in zone 98% of the time on the Midland Basin side.

It's a little different as we move over into the Delaware Basin where we -- one, we don't have the vertical well control; and two, quite honestly, we don't have the industry experience or the Diamondback experience in exactly the right zone.

So part of the reason that Kaes intimated that our costs in the Delaware Basin, the midpoint of which is moving just a little bit, is because we don't have confidently identified in exactly where the best landing zone is for some of these different horizons we're testing.

And Paul, can you answer specifically about what we anticipate, the $8.5 million high-res shoot that we're doing [Corpus with].

Right.

We're participating in a spec shoot, 385 square miles we're going to get that covers essentially all of our assets in the Southern Delaware.

We're really excited about it, state-of-the-art, high-resolution seismic.

Your question, it's a yes to both as far as better delineating the landing zone and the zones that we're already targeting, and also better delineating potential in additional zones that we've targeted.

As far as we know, there's upside there, but we just don't have as much data.

In the Midland Basin, most of our assets we're drilling between vertical wells on essentially 80-acre spacing.

So it's much easier to geosteer in the seismic.

We do have some seismic in the Delaware, and it's been very helpful in steering the wells that we've drilled to date.

But we're excited about the new data set and the relatively cheap cost that we're getting at, to really help us high-grade zones and additional -- or help us in the geosteering.

Great.

And then you guys have talked about you're seeing a significant production upload following utilizing ESP versus gas lift over in the Delaware.

I was wondering, can you quantify the delta between ESP versus gas lift?

Probably not yet, although we -- I ask the guys routinely because it costs more to run these ESPs.

I make sure I know how much incremental oil I have to produce to pay for the cost of running those ESPs, but -- did we put a slide in the deck, Mike, on ESP performance?

No.

So we have -- we track that internally, Gail, and that's probably for future dissemination.

But when we run these ESPs, we are seeing an uplift, and the uplift is paying for the cost of the ESPs.

So I think that's the right way to think about it until we can communicate more details.

Okay, great.

And then I'll sneak in one last one.

In regards to the completions, you're averaging about 1,500 feet per day in the Midland and it's 1,000 feet in the Delaware.

How do you -- is it -- are you guys going to able to as you get more efficient in the Delaware as you -- will that learning curve move towards that 1,500 feet as you are in the Midland?

Or is there always going to be a gap between the -- how much you can do in a day on the completion standpoint?

Gail, this is Mike.

The difference between the Midland and the Delaware side, it's not so much the efficiency of the frac crews.

They're all running 24 hours a day, 7 days a week, and they have the same kind of maintenance schedule.

But really the difference, as Kaes alluded to earlier, is on the size of the job.

So as we optimize and continue to optimize the jobs on the Delaware side, we're up to about 2,500 pounds per foot and that may -- we may over time, and again, as things change in cost, we may come down a little bit on the size, and that would allow us to pump the jobs a little faster.

But as we continue to have the difference in size between the Midland and the Delaware, you'll continue to have the difference in the amount of footage we can complete because the job [reduce are] that much bigger.

Your next question comes from the line of Jason Wangler with Imperial Capital.

Travis, just curious, as you talked about it, looks like you're going to kind of be 4 rigs and 6 rigs in the 2 basins as you think about either next year or even as you get to that 15 to 18 level, how do you see that split kind of breaking down in the longer term?

Yes, I think, as Kaes alluded to earlier, that as we continue to build out our infrastructure and allow us to produce our total fluid barrels in oil and gas more efficiently by having the midstream structure and the midstream facilities in place, you'll continue to see more rigs migrate towards the Delaware side.

But we just want to make sure when we bring the rigs over there that we're able to produce those barrels as efficiently as we can, which means we've got to have all those midstream infrastructure expenditures done.

So ultimately, we think about, from a capital allocation perspective, both areas are returning the same return metrics, that you'll have equal rigs on either side.

Okay.

So it's more of the infrastructure than anything else.

Okay.

And then just -- you picked up some acreage across the plays.

Just maybe -- obviously, you talked about the M&A side being -- kind of changing.

But just on the -- being able to pick up some acreage on bolt-ons and small things, is that still something that you're able to obviously do at a pretty decent clip, it looks like, from -- based on what you did in the third quarter?

Yes.

Those deals are really negotiated at the asset team level, and that's stuff they do in -- they do day in and day out and they do it strategically in advance of the drilling schedule.

And you really can't predict on a quarterly basis what the asset teams are going to be able to do.

But it's just smart business.

It's -- we need to know not only everything about our own leasehold, but we need to know what -- everything about what touches our leasehold.

And knowing that, that drives business development opportunities.

And I think our teams do a really good job at what we call little A. Big A, we handle at the business development levels.

The little A, which is these bolt-ons, the asset teams do a really good job of bringing those opportunities forward.

Your next question comes from the line of Jeff Grampp with Northland Capital.

I had a question on kind of lateral lengths here on Slide 5. Really appreciate that slide detail.

And clearly, longer laterals in the Midland, but obviously, I appreciate that you guys have kind of worked on that over the last couple of years and already 1.5 mile-ish in the Delaware.

But wondering is the Delaware configurated such or do you have the potential to potentially get that to the 8,500-ish that the Midland's at?

Or should we just not expect that to potentially be the case?

Just trying to get a handle on that.

Jeff, this is Mike.

Absolutely.

So the acreage we have up in the northern portion of the Southern Delaware near the River, most of the River tracks are all plus 10,000-foot lateral lengths.

As we go down into the acreage we acquired from Brigham, a lot of that we had some legacy portions that were 7,500 feet.

But most everything going forward, we're setting up for 10,000-foot lateral lengths.

So 10,000 feet is going to kind of be the norm.

The exceptions will be 7,500-foot or close to that.

So we're looking for somewhere closer to that 8,500 to 9,000-foot as kind of the average going forward.

Yes.

And as we continue to trade in the Pecos asset, you know just -- only acquiring it 8 to 10 months ago, we continue to increase the lateral lengths there as our team continues to trade and block that up.

Okay, perfect.

And then as a follow-up on a similar topic, have you guys kind of identified, I guess, an efficient frontier on lateral lengths, both on the Midland and Delaware side?

I don't know if those are necessarily different conversations that need to be had.

But just wondering, as far as if there's any changes on EUR per foot and obviously, tying that with efficiencies on the well cost side?

Or is it really merely a -- just technology issue of getting as far as you guys are comfortable at from -- as far as where technology stands today?

Jeff, I'll -- there's a couple of questions embedded there, and I'll kind of try to hit each one of them.

The difference between the Midland and the Delaware Basins, there are a few differences in that on the Delaware side, we do move more fluid in these wells.

So the 10,000-foot company-wide seems to be about the most efficient that we're looking at today.

But definitely on the Delaware side, 10,000-foot is about as far as we want to push.

Just being able to move that amount of fluid from a 10,000-foot well with the well deliverability we have in the Delaware, that 10,000-foot looks about right.

As we go to the Midland Basin side, we have several wells that are plus that, 13,500 to almost 14,500-foot lateral length.

So going to 15,000 foot from a technical standpoint is very doable.

From a efficient frontier standpoint, we still feel we have most of the field set up just from a lease geometry standpoint for 10,000 footers.

But 15,000 footers are very doable on the Midland Basin side.

Your next question comes from the line of Richard Tullis with Capital One.

You talked a little earlier about adding the 10th rig in the coming week.

Just wanted to verify, are you planning at this point to add an 11th rig early next year at the current oil price?

I think we're happy to have that discussion.

I don't think we're there yet, but we definitely plan our business in a $50 world.

And in a $50 world, we're adding rig 11 at some point in 2018.

I think in a $55 world, where we are today, that's just going to happen a little sooner.

So we had the conversations on rig 10 probably 30, 45 days ago, and that rig is now starting to work around this time.

And we're consistently updating our budget based on oil price and our projected operating cash flow and planning our business ahead with that respect.

So conversations are happening, but I can't commit to any time frame yet into 2018.

And looking longer term, if oil price gets to a sustained level, like cause for running 15 to 18 rigs on the current acreage, how would that impact the company's ability operationally to handle larger acquisitions going forward?

Well, you want to build the organization appropriately to handle the 15 to 18.

As I said, we're suited now to run the 10 rigs.

So to get to 15 to 18, we'll be building the organization accordingly.

At some point in time, with these larger acquisitions, you're going to have to start coming with people.

And again, from a business development perspective, we don't see a lot of big deals out there that fit within our Tier 1 threshold.

So ultimately, that's our responsibility as leaders to make sure the business development takes everything into consideration, and one of those things that we consider is human capital.

So it's what we do, Richard.

So it wouldn't be an impediment to doing a deal.

Your next question comes from the line of Dan McSpirit with BMO Capital Markets.

If we could revisit the subject of paying a dividend, do you see paying a dividend as the ultimate point of distinction in this sector; that is, either a producer can generate sufficient and consistent free cash flow to return to shareholders or it can't?

Yes.

I don't know, Dan, about the whole industry.

What I'm going to focus on is what Diamondback has done.

The commentary that I've mentioned has pivoted in the last 6 weeks to living within cash flow, that's not a new commentary for Diamondback.

I tried to illustrate that by -- for 11 quarters now.

If you add what we've spent in 11 quarters versus the operating cash flow, we've actually generated more operating cash flow.

So I don't know where the discipline is going to go from an investor perspective, but Diamondback very clearly believes that returns matter and capital discipline is part of our DNA.

It's what we've always done.

And I think that's the right way to run a business, now that we've grown so much as a company.

It's fundamentally the right way to think about the future.

Got it.

I appreciate the context and the honest answer.

And if we could just revisit your remarks about other operators having trouble prosecuting their plans.

Those same producers have suffered from production slippage that maybe comes from new and less-experienced hands in the field.

It appears Diamondback hasn't suffered the same.

Here's an obvious question for you.

Why hasn't Diamondback suffered the same?

And how is the company somewhat immune to what could be a tighter market for labor and services?

I'll take this one.

I think there's a relentless focus from our organization on execution, and you hear that in every quarterly call.

I don't necessarily like to talk about other operators, but we've focused on our plan in 2018 and we had planned on bringing in this fourth operated frac crew in August.

And we were having those discussions in February.

And we've made sure we had the extra supervision on-site and made sure that we were planning our business accordingly and making sure we didn't stub our toe going into 2017, which was always going to be a year about execution after our industry returned to growth after the downturn in 2016.

(Operator Instructions) Your next question comes from the line of Michael Hall with Heikkinen Energy Advisors.

I guess -- I just wanted to kind of hit on some questions around high-level capital efficiency as we think about the 2018 program versus 2017 program.

What would you say are kind of the key headwinds and then also tailwinds to capital efficiency, perhaps broken up by the Midland Basin and the Delaware Basin, as we think about a dollar spent in '18 versus one spent in '17?

Well, Michael, in 2018, obviously, the Delaware will be a higher percentage of total capital spent.

I mean, I think from a rate of returns perspective, we're still very bullish on rate of return out there.

And from a cost perspective, I think our drilling guys continue to get better and cut days on location and increase cycle times on the Delaware.

Going to the Midland Basin side, as horizontal production continues to increase as a percentage of total, we're still going to push our cash costs down.

As we've talked about, the organization is set up for running the 10-plus rigs that we need today on a G&A perspective.

And from an LOE perspective, putting in this infrastructure is going to only increase our net backs as we look into 2018.

And as you look at, I guess, both assets in the Midland Basin and the Delaware Basin, broadly the industry has had a pretty big tailwind from an improvement in productivity per 1,000-foot from a change in completion design to landing zones, et cetera, over the last couple of years.

How does that rate of change look as you look forward in each basin for Diamondback?

I'd say the rate of change in the Delaware still looks higher than the Midland.

I think on the Midland Basin side, given our experience there over the last 5 years, the range of outcomes is a smaller range today than it was 2 or 3 years ago when the big step change in completion design happened.

So on the Delaware side, we continue to test different landing zones and different completion designs.

I think the potential for increased performance on that side of the basin is higher at this point.

Okay.

And then, I guess last on my end is you've alluded to infrastructure spend as a percent of total capital coming down to a somewhat more normalized level in '18 as you move past the first quarter.

What is a more normalized level of infrastructure spend relative to total capital look like for Diamondback?

Yes, on a long-term basis, it's probably an 8% to 10% of total capital spent on infrastructure.

And really, that's -- the big heavy lifting is going to be done because these oil pipelines will be sized for full field development.

And then after that, it's just adding the water infrastructure and the disposal infrastructure on an a just-in-time basis on both basins as volumes grow.

There are no further questions at this time.

Travis Stice, CEO, I turn the call back over to you.

Thanks again to everyone participating in today's call.

If you've got any questions, please contact us using the contact information provided.

Thanks again.

Ladies and gentlemen, this concludes today's conference call.

You may now disconnect.