Diamondback Energy Inc (FANG) 2019 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy Third Quarter 2019 Earnings Conference Call.

(Operator Instructions) As a reminder, this conference is being recorded.

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

Sir, you may begin the call.

Thank you, Annie.

Good morning, and welcome to Diamondback Energy's Third Quarter 2019 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; and Kaes Van't Hof, 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.

I will now turn the call over to Travis Stice.

Thank you, Adam, and welcome to Diamondback's Third Quarter Earnings Call.

Normally, I'd jump right in and review key milestones in the quarter, but with the challenging market conditions, I feel the need to reflect on where we are today.

Investor sentiment towards energy remains decidedly negative even in the face of commodity prices performing fairly well this year.

The U.S. rig count is now down over 25% year-over-year.

And we expect that downward trajectory to continue with frozen capital markets, tighter lending conditions and the search for free cash flow sector wide.

As a result of these conditions, we expect continued pressure on U.S. production growth numbers and expectations for 2020 U.S. production growth need to recalibrate lower, all of which may potentially support oil prices pending demand growth.

We believe these market conditions call for a 2020 investment framework that's focused on flat-to-down capital spending, an efficient low-cost structure and returns on capital in excess of cost of capital, all of which are strategies Diamondback has been focused on for many years and plan to address with our 2020 plan presented today.

Late last year, we laid out our plans for the upcoming 2019 year.

There was tremendous concern surrounding Diamondback's ability to integrate the Energen acquisition and deliver on acquisition strategies.

The fundamental question was whether we could maintain our industry-leading cost structure and capital efficiency on a company with twice the scale and double the people.

We also spoke of the significant shift to consistently return capital to shareholders while continuing to grow production, and we set ambitious targets for production growth and execution on operational efficiencies.

Since then, we've exceeded our own expectations of synergies realized from the Energen transaction, delivering on every synergy ahead of schedule and added greater value to our shareholders, even creating a synergy scorecard updated quarterly since the transaction closed to transparently document our progress.

We have successfully taken our Midstream entity Rattler public, raising over $700 million in proceeds and creating a high-margin, high-growth midstream subsidiary.

We have dropped down mineral assets from Diamondback and Energen to Viper, increasing Viper's exposure to Diamondback while receiving cash and stock in consideration.

We've executed on our grow-and-prune strategy by divesting legacy Energen conventional properties for gross proceeds of $285 million.

We have realized and continue to realize operational efficiencies with average well cost today over 15% lower than Diamondback's cost prior to the Energen acquisition, leading industry in efficiency measures such as recycle ratio and demonstrating the strength of Diamondback's execution machine.

We've accomplished a remarkable set of corporate objectives while still delivering on execution and cost measures.

These are the things I reflect on when considering Diamondback's performance during 2019.

Our business is complex.

And this quarter, we had a number of anomalous events that caused several of the metrics we follow and are held accountable for to underperform our expectations.

We understand that the market monitors performance on a quarterly basis, which is why we have been as transparent as possible as to the impact of these events and our path forward.

But let me be clear, none of this performance requires a course correction or change in strategy at Diamondback.

After growing significantly for the first 2 quarters of the year, Diamondback's oil production declined in the third quarter due to the sale of 5,800 barrels per day of low-margin oil from our Central Basin Platform asset effective July 1, 2019.

Without considering this effect, Diamondback's quarterly production grew, but the oil production declined.

The completion of 18 wells in our Vermejo area in Reeves County and 14 wells in Glasscock County, 5 of which were DUCs completed or drilled rather prior to the closing of the Energen merger, drove oil cut down since these 2 areas begin production with oil cuts below 65%.

These 32 wells made up over 35% of total gross wells completed in the third quarter versus 12% of the wells completed in the first half of the year and 15% of the wells that will be completed in the fourth quarter.

While we are accountable for forecasting our production, the impact from offset completions were dramatic during the quarter, another strong reminder why we did not provide quarterly guidance.

Specifically in Howard County, one of our most active and highest oil cut fields, the combination of Diamondback frac activity and offset operators both to the east and west of our leasehold cut production in half or over 20,000 gross barrels of oil per day during portions of the quarter.

While we'll plan to model this impact more conservatively going forward, we expect frac impacts to continue to be significant, primarily in the Midland Basin with operators in full field, multi-well pad development mode.

Taking all of this in consideration, along with current production levels, we expect fourth quarter 2019 oil production to grow over 3% from the third quarter, but offset frac impact is still expected to be large in the fourth quarter, particularly in Howard County, where there's significant rig and completion activity due to the economics of the area.

Looking ahead to 2020, our goal in putting together our capital plan was to maximize oil-weighted production growth within a similar budget framework as 2019, getting more with less.

As a result, we expect to grow oil production 10% to 15% year-over-year and complete over 10% more net lateral footage than 2019.

Most importantly, our budget assumes we cover our budget and base dividend above $45 oil and have over $675 million of predividend free cash flow at $55 oil.

Our 2020 commodity price assumptions have weakened since our last communication around 2020 free cash flow, which now assumes $13 per barrel NGLs, down almost 40% from May and $1.50 realized gas prices.

Regardless of the commodity price assumptions, we are committed to offering an industry-leading combination of growth and free cash flow yield in 2020.

We believe this capital operating plan reflects the optimal capital efficiency for achieving differential growth and significant free cash flow in 2020.

Should commodity prices decline, we will be prepared to act responsibly and cut capital further, just like we've done multiple times in the past.

If commodity prices rally, we plan to use excess free cash flow to accelerate our capital return program and reduce debt.

The biggest concern related to the miss we experienced versus internal and street expectations in the third quarter, and as a result, 2019 full year oil production are, one, how can we be confident the oil production miss in the third quarter is not the start of a continuing trend.

And two, how are the lessons learned from the third quarter accounted for in the forward guidance.

Well, first, when there's a miss of the magnitude that we just experienced in the third quarter, we have to fundamentally reexamine the assumptions that led to this performance.

We've done this, and as a result, we've more conservatively modeled our expectations for the future, particularly external issues that are out of our control, such as offset operator frac hits like those experienced in the third quarter.

Full field development by Midland Basin operators, including Diamondback, increased the amount of production water down on average throughout the course of the year, which was not modeled conservatively enough in 2019.

These are operational challenges, not reservoir problems.

Second, we have increased the amount of co-development zones across more productive zones, which we began in 2019, and we expect to increase that in 2020, particularly in the Midland Basin.

While this strategy is expected to maximize the net present value and extends inventory life, in some areas, this capital allocation decision generates lower first year oil production per developed pad.

Our Midland Basin development plan prior to 2019 was predominantly focused on the Wolfcamp A and the Lower Spraberry.

In 2019 and carrying into 2020, we're increasing our exposure to other zones such as the Jo Mill, Middle Spraberry and Wolfcamp B due to the improved well performance in these particular zones, and the estimated net present value benefit of this co-development.

This holds true to a lesser extent for the Delaware Basin as well, where we have more Second and Third Bone Spring development planned, along with our primary development zone in the Wolfcamp A. Again, this is a well mix issue, not a reservoir problem.

Lastly, on a percentage basis, we're adding fewer new drill, high flush volume wells and high oil cut wells to the 2020 production mix than in previous years, which also lowers the corporate oil mix.

You can see in our 2020 guide that we're now guiding to oil only to address this confusion.

While these changes in modeling assumptions and development strategy translate to an overall lower 2020 oil production expectation relative to consensus, our 2020 capital efficiency will be slightly better than in 2019 due to execution improvements and lower cost structure as measured by drilling capital spent per barrel of oil production added after taking into account our over 36% oil-based decline rate in 2020.

Our current capital forecast for 2020 incorporates today's service costs, which should decline from here pending a reduction in expected basin-wide activity levels.

As a result of all the data presented here, I'm reiterating that this is not an inflection point or a course correction and the value proposition for Diamondback remains unchanged: comfortable double-digit oil growth, a mid-single-digit free cash flow yield and the lowest cost structure in the business.

Today, Diamondback is poised to grow production at the highest margin and capital efficiency in the industry while maintaining a strong capital structure and activity -- and actively returning cash to shareholders.

With these comments complete, operator, please open the line for questions.

(Operator Instructions) Your first question comes from the line of Neal Dingmann.

Your 2020 oil and total production guidance suggests about 10% to 15% growth in that 19 midpoint while still generating, what I would assume, around 5% free cash flow yield.

My question is, could you speak to some of the assumptions around the guide?

You kind of hit on these specifically, how you risk this and then the assumed number of rigs and spreads and potential OFS and OLS costs baked in there?

Yes.

So I'll answer them in reverse.

The OFS costs, we just baked in what we actually saw in the third quarter.

So again, as the activity level continues to slow down out here in the Permian, we expect to continue to see service cost reductions, and actually is going to provide a tailwind for our free cash flow generation next year.

I think specifically, the risking that we took on frac hits was more aggressively modeled this year than we did in 2019.

And what that means is that you actually end up with a more severe hit across more wells that lasts longer.

But also when you look at the things that impacted the third quarter and how that adjusted some of our assumptions on a go-forward basis, even down to the details of like how long it takes for a well to recover once it's been watered out, we've extended that time.

When the co-development of some of the zones we've talked about, we've extended the time to peak production in order to also reflect kind of what we've seen in the third quarter.

But look, when you have a miss of the magnitude that we did in the third quarter, you really have to, like I said in my prepared remarks, re-examine every single thing we've done and we -- every single assumption that was made, and we've done that.

I mean we're down to -- we're looking at the daily increase in your Hertz rate on sub pumps after frac.

We really broke the business down into a fundamental part.

So I think when you stub your toe, like we did in the third quarter, you've got to be able to adjust your future forecast to make sure that you can hit those numbers, and we've done so with the assumption we put in place.

I think the rig cadence and completion cadence, the low end of our guidance probably is going to reflect in order to -- if we hit that low end, it will probably be a function of slowing down activity.

And the high end of the guidance is probably a function of saving some money and maybe getting a couple of more wells drilled and completed during the year.

Got it.

Got it.

And then lastly, could you speak to Slide 6 in your deck, particularly the part up on top there where you talked about, and you get this a little bit in the prepared remarks, about the increased co-development between zones in the Midland and Delaware?

I mean should we consider this a shift in overall strategy?

And will this impact your M&A going forward?

I don't think there's any read-through to M&A.

M&A is a function of a low-cost, high efficient operator, acquiring assets that we can do more with under our execution and cost structure than others can.

But it does reflect -- it does reflect how we think about the future.

We believe that these -- we believe that these co-development is fundamentally the right thing to do, and that's the way our strategy is laid out for the next several years.

We do have another question from the line of Brian Singer from Goldman Sachs.

To follow up on a couple of comments you mentioned.

First, can you add a little bit more color on the frac hit impact that you're forecasting for next year and how that relates relative to what you've seen this year?

And then as well, you mentioned not a reservoir issue.

So we see the impact when -- on the negative side to production.

Can you talk about what happens when that goes away, how the wells respond, how quickly they get back?

Or if they get back to the production levels that they were at before the hit and how that leads to a declining -- or how that leads to an evolving decline rate in both basins?

Yes, so specific, as we've done the forecasting in 2020, we've looked at each individual field.

And so we've gone back and historically modeled the number of days of 0 production of oil.

And then once it starts returning oil, the number of days it takes to get back to peak production.

And both of those 2 elements, the number of days that it produced 0 plus the number of days that it takes to get back to peak production were extended in our forecast for 2020.

And we've done that in each of the areas.

Now again, what we've seen is they do return to peak production.

And so that's why I make the comment that it's not a reservoir issue because the EUR, the area under the curve, remains unchanged.

It's now the delivery of that EUR has been more conservatively modeled with respect to these frac hits.

Yes.

And I'd say, Brian, on top of that, we've been modeling frac hits for a long time in Spanish Trail.

In this case, Q2 -- or sorry, Q3 was extraordinarily difficult in Howard County because of the size of the pads offset us, right?

Traditionally, we've completed 4 well pads.

To the east of us, there's a 24-well pad completed and that frac spread was on-site for 2.5 months and so that's a significant hit even higher than what we originally expected.

So that particular field, the Howard County field was hit by about 12,000 gross barrels of oil a day for the whole quarter, which on a net basis is about 8,000 net barrels a day.

I'll just add to that, Brian, when you look at what we've been doing in Spanish Trail now for over 5 years, we've seen the impact of frac hits and are confident that because of that experience, we've seen full recovery.

And it's not just the first time you hit it.

Some of these wells in Spanish Trail have been hit multiple times.

But each time, they return back to their previous forecast.

Great.

And you partially answered this, just -- in the earlier question.

But if we think about that CapEx -- if you think about the CapEx and the production range, and let's assume that the CapEx is at the midpoint of your guidance for 2020, is there a scenario -- or what would be the scenario where production would end up at the lower end of the range?

And I think you kind of highlighted what the scenario would be at the higher end of the range.

But essentially, if you're investing at the midpoint of your CapEx guidance, what do you see as the risk to both the downside and the upside to the oil production guidance that you put up?

Yes, certainly, the things that impacted us in the third quarter, we believe we've addressed those more aggressively or more conservatively in the form of forward guidance to spend the same CapEx next year, the midpoint of the CapEx and coming at the low point of the oil guide, then you've got to have something -- you've got to have poor well performance that we're not expecting right now.

And we've not guided that direction at all.

As I said, the low end of the guide is more a function of lower total activity.

We do have another question from the line of Derrick Whitfield from Stifel.

Perhaps for Travis or Kaes, as we look at the 2020 capital program, are there any quarters that have outsized activity in Glasscock or Vermejo next year?

Yes, I think the quarters -- again, we've learned of what we saw in the third quarter of this year.

And so the guidance that we put in place reflects a more steady guide of Vermejo and Glasscock County wells on a quarter-over-quarter basis.

Great.

And perhaps for my follow-up, referencing to Slide 7, your asset base is quite resilient at lower prices.

Assuming lower growth in 2020, how would this slide look for 2021 in terms of your cash flow breakeven?

Yes, Derrick, I mean that's all dependent upon activity, right?

I mean at the same activity level, cash flow would still grow in 2021.

I don't think it would grow 11% to 15%, but you'd still see growth.

We feel like we have a lot of tailwinds going into next year, particularly 10% better realizations on the oil side for the year.

We've got some LOE tailwinds where LOE is going to be declining throughout the year next year.

So that all supports a lower breakeven as we continue to grow, but don't continue to spend every dollar we make back in the ground to fund that growth.

And Derrick, I just want to add, since you brought up Slide 7. When you look at the $55 oil bar, it's $675.

As I said in my prepared remarks, we had originally communicated $750 million of free cash flow at $55 oil.

But the deterioration of NGLs right now at $13 a barrel, we lost $7 a barrel relative to our last communication, and that's about $100 million worth of free cash flow that went away from us in that scenario.

We'll have another question from the line of Tim Rezvan from Oppenheimer.

I had an organizational question, which perhaps is best suited for Travis.

In the last year, Diamondback closed the Energen acquisition, they've IPO-ed another subsidiary and the organization's lost its COO in September.

I know Diamondback is an organization that's prided itself on running lean when there's a laser focus on G&A.

But I guess my question, Travis, is with your organization's complexity and the 3Q miss that we saw last night, is the organization too lean?

Are you rightsized to kind of execute like you wanted to?

And should investors be concerned about the complexity?

No.

Complexity is part of our fundamental DNA.

What looks complex to our investors, we intend to make look simple.

And organizationally, I've said -- I think in the last earnings call, I said we're probably 150 people short.

And we're probably still somewhere around 100 people short.

And that's across every aspect of our business.

But I'm not going to stand here and say that the function of third quarter was a result of, one, either complexity; or two, lack of people.

We own it.

And that's what you expect me to do is to staff the organization adequately and to simplify complexity and that's what I intend to do every day.

Okay, okay.

And I guess, as my follow-up, in your prepared comments, you talked about kind of a well mix issue from more zones and kind of your pad development.

Can you talk about why year 1 oil goes down?

Is that a controlled flowback issue?

Or is it because of oil cuts in other zones?

I'll leave it there.

No.

Yes.

No, the oil goes down on a year-over-year basis because when you add in a Jo Mill or a Middle Spraberry well into a 4-zone development, it has a different oil delivery type curve than does the Wolfcamp A or the Lower Spraberry, which we've historically had a heavier dose of those 2 development zones.

So when you look at the oil relative for a 4-zone where I've added in Jo Mill and the Middle Spraberry, you see the corresponding impact.

We do have another question from the line of Jeff Grampp.

I was wondering -- it looks like the 3Q Delaware well costs are already at kind of the low end of your 2020 budgeted cost there.

I was just wondering, is that, I guess, a well mix consideration that maybe drove 3Q lower?

Or do you think -- is it fair to think that maybe there's some embedded conservatism in what you guys are assuming budget-wise for 2020?

Yes, Jeff, Vermejo is the cheapest of the 3 fields in the Delaware Basin from a D,C&E perspective.

So we did have a lot of Vermejo wells come through in the third quarter, which is why that number looks low relative to the guide.

But as Travis said, we're not guiding to service cost reductions from where we are today.

We certainly expect to continue to see some deflation and continue to get some efficiencies.

But for the third quarter relative to 2020, really that's more -- a higher percentage of Vermejo rolling through the capital side.

Yes, listen, as I prepared for this quarter, we go through our normal quarterly review process, where we do a well-by-well analysis of wells that have contributed in the quarter.

And I couldn't be more proud of the continued focus, laser-like focus of the operations organization on driving cost out and improving recovery.

So that part of our DNA is spectacularly in place, and it's something I monitor almost on a daily basis.

Got it.

Understood.

And for my follow-up, just kind of a bigger picture question for you, Travis.

Can you talk about why 10% to 15% is the right growth for Diamondback in 2020 versus evaluating maybe trade-offs of slower growth and more free cash flow to fund the buyback and maybe dividend growth?

And just kind of how you guys evaluated the potential trade-offs of those types of scenarios?

Yes, it's not a precise calculus granted, but we had to balance this.

We're trying to -- and we believe we have presented a business model that has this kind of sustainable free cash flow on a go-forward basis.

And so if we had lower growth and greater cash flow in 2020, then you're going to impact the out-years of your development plan.

So what we believe we've done is struck what is an appropriate balance of maintaining and sustaining the free cash flow generation that this machine is capable of, but at the same time, kind of at the upper end of anybody out there in terms of production growth.

And listen, I still believe that Diamondback is the best executor and the lowest cost producer, which should grow.

And that's what we've presented in the 2020 guide.

Our next question from the line of Ryan Todd from Simmons Energy.

Maybe 1 more follow-up on the co-development strategy.

Does the shift towards more co-development actually have any impact in the way that you approach facility design or construction or even on operating costs?

Yes, not really.

I still expect facility cost and operating cost to decline year-over-year, quarter-over-quarter, but that's part of my predisposition though, but the co-development whether the -- the only thing that could possibly impact that would be is if we add, like in the Delaware, a higher percentage of Second Bone, Third Bone Springs wells that have a higher -- higher water cut and will not have to adjust it.

But we've accounted for all of that facilities design in our 2020 guide.

Yes, Ryan, pad size has been changing, the mix of the wells within the pad is changing.

So overall, your facility size and spend is similar.

Now in 2020, we do have more gas lift projects in our infrastructure budget.

Those are onetime expenses that should roll through in 2020 and help LOE over the long term.

Okay, great.

That's helpful.

And then maybe just a question on use of cash.

I mean you guys have a significant increase in free cash flow next year.

In terms of use of free cash, I know you get asked about this all the time.

But can you talk about priorities for use of cash, specifically like buybacks versus dividend growth?

How do you look at the balance there?

And have you ever entertained the idea at all of a variable distribution in excess of a base dividend rather than a buyback?

Yes.

I think if you go back and look at the previous communications that we've had about what our primary form of return to shareholders is and that's -- it's in the form of an increasing dividend.

And that's what we intend to do on a go-forward basis.

The variable distribution is something -- that's really not something we've considered.

We don't want to overly complicate the business.

There's not a lot that you can do with free cash flow.

And we believe we've addressed each of those in the form of share buyback, potential for -- as we said, we're always going to increase the dividend on a go-forward basis and that's what we intend to do.

We do have another question from the line of Drew Venker from Morgan Stanley.

Just wanted to follow-up on the guidance for 2020.

I was hoping you could give us a sense in very simple terms, how much downtime you're assuming of your base production for 2020.

And if you can compare that to what you had assumed for the original 2019 guidance?

Yes, Drew.

I mean, traditionally, the base production, we assume high single-digit downtime as a percentage of total, 6%, 7% downtime.

That number has stayed about the same for your base production.

What we've risked is the additional production, right?

So not only are you risking the new wells put online, but on top of that, via the data we have, we shut in offset wells within a certain perimeter of the well getting completed ahead of time.

So your traditional risking stays in place, but on top of that, you need to risk any well that's being watered out within a certain parameter or a certain diameter of the well that you're completing for a certain period of time.

Okay.

But presumably, you could still have this -- that watering out or shut-in impact from new wells on offset operators that would impact your base production.

Or am I thinking about that incorrectly?

Yes, communication between us and offset operators is important.

I think in the Midland Basin, particularly where we're all really close to each other and just not big deals, that's important.

But we model that impact via some conservatism.

And we also know where those guys are operating.

We have a view into their 6-month frac schedules.

We take that into account.

I think what happened here is you had a larger pad on watering us out for a longer period of time than originally expected.

And therefore, going forward, in those fields where we have offset operators, we're very conservative on the water out piece there.

Okay.

I think just to wrap that up.

I mean we've got the visibility.

We believe we've got more data analytics-driven decisions -- data analytics now that can increase the predictability's effect.

And we've accounted for that and it's in our go-forward plan, probably more so in this year's plan than any plan we've previously submitted.

Understood, Travis.

I guess, as a follow-up, as we think about 2020 and the transition overall to, I think, bigger projects on average, how do you think about the cadence of growth throughout 2020?

Is there a pretty wide range of project sizes and timing that will affect the cadence you got throughout the year?

If you could just give some more color on that?

Yes, not too much.

Drew, project size isn't changing much, I'd say.

The type of wells within the project is changing, right?

So Midland Basin, we still do 4, 5, 6 well pads, but there's more co-development between zones.

And so from a production growth perspective, we are going to get back to growth in the fourth quarter and grow fairly consistently through the first -- the first half of 2020.

And there's not a big lumpy month, a big lumpy quarter in that assessment.

It's just going to be consistent POP growth and production growth.

And then similar growth in the second half of the year do you think is still consistent for '20?

Yes.

We have another question from the line of Asit Sen from Bank of America.

Thanks for the details on the frac heads you provided to quantify in 3Q.

Could you, Kaes, broadly quantify the impact of frac hits that you're assuming in the 3% sequential growth in 4Q?

Yes.

Traditionally, we model about 8%, 10% of our total production being watered out on any -- at any given time.

I think as you think about the fourth quarter, Howard County is coming back.

Today, that field's back up to 40,000 gross barrels a day from the bottom of 25, but you are watering out other areas such as Spanish Trail and small stuff in Pecos, but on an overall basis, I'd say, the percentage of total production, our frac hit will be lower in Q4 than it was in Q3 and pretty consistent through 2020, especially as you get the full year development in the Midland Basin.

Okay, great.

And then some of your peers have -- are showing strong results in the third Bone Spring.

And just wondering if you have any incremental thoughts on that zone and the number of completions you're planning to complete in the zone.

I couldn't exactly figure it out on Slide 6, but any rough estimation would be good.

Yes, I think we're excited about it in the ReWard area and the Vermejo area.

As you get into our Pecos County asset, we're more excited about the second Bone Spring and the third Bone Spring.

So while we're not as excited about the second bone in ReWard and Vermejo, that's where the third bone is prevalent.

And then on the contrary, in the Pecos area, particularly on the eastern portion -- or western portion of the Pecos area, the second bone is probably our secondary zone behind the Wolfcamp A.

We do have another question from the line of Jeoffrey Lambujon from Tudor, Pickering, Holt Company.

Just a few follow-ups on co-development.

First one is, as we look at the number of wells and zones like the Wolfcamp B, the Middle Spraberry and the Jo Mill, on the Midland side and the third Bone, second bone on the Delaware side as a percent of total wells for the next year, how is that percentage compared to 2019's mix?

And how does that change as you look forward to 2021 and beyond?

Yes, Jeff, I'll take the Delaware first because it's less of an impact in 2019.

Let's say, the Wolfcamp A was almost 90% of 2019 development in the Delaware Basin, going to closer to 85% or so in 2020.

In the Midland Basin, the big move has actually happened in 2019 versus 2018, 2017.

So if you take 2018 and 2017, we're probably closer to 65% to 70% Wolfcamp A and Lower Spraberry versus 2019 and 2020, closer to 50% or 55% in the Wolfcamp A and the Lower Spraberry.

Okay.

And should we expect -- just a quick follow-up to that.

Should we expect that percentage to continue kind of decreasing over time as you continue progressing on co-developments?

I don't think it will decrease.

I think the shift has been made, and we are getting what we believe to be all the economic zones at once in the Midland Basin.

Got it.

And then on these additional zones, can you just give more detail on how the early time productivity compares?

Again, as you look at the Wolfcamp B and the Middle Spraberry, for example, versus what you've historically seen in the Lower Spraberry and Wolfcamp A?

Yes.

So very clearly, the Middle Spraberry takes longer to clean up.

So you do have less production early time in the Middle Spraberry and the Jo Mill versus the Lower Spraberry.

And between the Wolfcamp A and the Wolfcamp B, Wolfcamp A is just so strong.

They have a similar production profile between the 2 Wolfcamp zones, but what we are, the B is not as good as the A, but still highly economic.

So you have high early time production, just not as high as what you see in the Wolfcamp A.

We do have another question from the line of David Deckelbaum from Cowen.

I was hoping to get some color.

You talked a lot about the '20 guidance.

You laid out that free cash projection of $675 million accounting for the lower NGL prices.

Can you add more color on just the Carlyle JV, the 15 to 17 wells being drilled?

One, where that development is taking place?

And two, what you think the net cash benefit is going to be to Diamondback this year?

Yes, David.

So this is the first year where the Carlyle JV is a significant portion of our total well count, 16 wells, about 5% of 2020 total well count, that's in the San Pedro Ranch, which is the Southeast corner of our Pecos County asset.

Carlyle and Diamondback have elected to drill out the northern portion of that, the north half of that in 2020.

We have to account for that at 100% of the production, but also 100% of the capital.

And we estimate that JV in 2020 actually produces $50 million more free cash flow.

And then we're presenting on Slide 7. So we're putting up 15% of the capital for 20% of the production.

And after certain return thresholds are met, we will control 85% of the production.

Okay.

So that's helpful.

The other question I had was just -- you all made a lot of headway this year in terms of LOE coming down.

It sounds like you have some infrastructure investments that you're hoping will pay off to a similar effect in '20.

The margins that you're assuming, I guess, in that '20 free cash guide, is that just holding your current cost structure flat?

David, I think we're going to see another couple dimes of help here into the fourth quarter and into 2020 on the LOE side.

So we're kind of modeling mid-4s for LOE going forward.

But every cent counts, $0.01 is $1 million of free cash.

So there's certainly some benefits and some tailwinds we'll see even into 2021 as we get some permanent infrastructure in place.

We have another question from the line of Jason Wangler from Imperial Capital.

Just had 1 question.

As you think about the free cash flow you talked about in 2020, where does reducing the debt on the credit facility kind of come into that equation?

Is that something more that you look at asset sales and savings?

Or is that something that's kind of normal course of business alongside the other initiatives?

Yes, Jason, we feel like we've got the revolver to a point where we're comfortable.

We have a significant borrowing base behind it.

We haven't even added the Energen properties, which had a borrowing base of $2 billion.

So our pro forma borrowing base is closer to $5.5 billion.

We were trying to run this company like an investment-grade company, and we hope that time comes.

And at that point, we would reduce our revolver borrowings to 0 and term out our debt.

But from an absolute basis, are there things to do at the margin?

Certainly, but we feel really comfortable about our growth profile and what our absolute leverage and leverage metrics look like.

I have a question from the line of Betty Jang from Crédit Suisse.

I appreciate your comments earlier about showing steady production growth cadence through 2020.

I was wondering if you could give us some type of range on where oil production could be in 4Q 2020?

Yes, Betty, I'm hoping we exit the year in the mid- to high teens exit-to-exit versus Q4 2019.

Got it.

And then the 4Q '19 level will be sort of in the low 190s, so that will put us in probably close to mid-220s for 4Q?

Yes.

I mean I think we tried to very accurately describe what we think Q4 2019 is going to look like and the growth rate on top of that.

Great.

And then follow-up is on buyback, how are you guys thinking about pace of buyback going forward?

Would it more likely follow the quarterly free cash flow cadence through the year?

Or would it be pretty opportunistic depending on price actions?

Yes, primarily, it will be based on free cash flow and being revolver neutral.

I certainly think we have an opportunity here to be a little more aggressive in the near term.

But over the long term, it's focused on buying back stock within the free cash flow framework.

We have another question from the line of Richard Tullis from Capital One Securities.

Travis, when you look at the oil mix projected for 2020, I guess it's down a couple percent from where you were, say, in the first half of this year.

How do you see the oil mix trending over the next several years assuming no additional acquisitions?

Does it move closer to the 1P reserve number?

Yes.

Ultimately, we'll move closer to the 1P number.

But for the next couple of years, I think what we've got modeled at this kind of activity pace and that balance of kind of growth and yield, you'll -- I think you'll see more of a steady oil cut on the go-forward years.

On a yearly basis.

On a yearly basis, yes.

Okay.

And just lastly, shifting over to the Limelight Prospect.

It sounds like you had some appraisal drilling in the past quarter.

What are your thoughts on what you saw there?

And how many wells might be planned for 2020?

Yes, we certainly -- we didn't disclose any results this quarter, but we like what we saw, and we've got another appraisal well, I think, planned back half of this year -- or back half of next year.

We have another question from the line of Charles Meade from Johnson Rice.

You guys have covered a lot of ground already this morning.

I think I have just a couple quick ones.

First one, on the Vermejo area, I understand that, that's relatively gassier, but I think -- it's also my understanding that that's one of your -- or at least has been one of your best, most attractive areas at the top of the portfolio.

Is that still the case?

Or has there been anything...

Still the case.

And then second, this is maybe a bigger picture question, Travis, about the service environment.

You and a lot of other operators are talking about service -- deflation in service costs.

But from the outside looking in, and certainly, you see this with their stock prices, that looks like a sick business model that's not doing very well.

So do you guys ever -- do you guys spend any time thinking or talking about the viability of your service partners?

And is that something that you have anything you'd want to share your thoughts on?

Yes, look, we need that sector to perform well.

They're business partners, and they're vitally important to us, prosecuting our development plan on a go-forward basis.

I believe that the headwinds the upstream E&P guys are facing are also being applied to the service sector.

But I don't concern myself with viability as much as I do, maybe, availability.

There could be some elements of the OFS sector that gets put under more harsh pressure than some of the big guys.

And that's why we try to be open and transparent with our service sector business partners is to make sure that they understand our plans and we understand their plans.

We have another question from the line of Biju Perincheril from Susquehanna.

Travis, when you're looking at the frac hits and impact, when you look at how quickly those wells can recover what -- is there a relationship between the vintage of that well -- the producing well on the formations?

And how should we think about that?

No, I don't think vintage is the relevant indicator.

It's just proximity.

So if you're within a certain amount of lateral feet from that particular well, we shut in the well we're producing early and then it comes back 5 to 10 days after the frac job is complete.

Yes, we've got wells.

I think, I mentioned earlier, we've got wells in Spanish Trail that had been what, Danny, frac hits 5 or 6 times over the last 5 or 6 years.

And as we go through and sit down with our reserve auditors, you see the frac hit and then you see the recovery back to the former decline rate.

So it certainly didn't have anything to do with vintage, it just really has to do with the proximity where the offending water is being injected in the frac operations.

Got it.

And then just going back to the earlier question on the oil mix.

So if you're in that maintenance mode that you've referenced in the press release, the $1.7 billion CapEx scenario.

Not that, that's what you're doing.

But if that's the case, sort of we better understand the impact on flush wells coming on, where could the oil mix line out?

Yes.

So oil decline, base decline is 36%, 37% next year.

BOE base decline is 33%.

So you will see a little bit of a lower oil percentage if you went into maintenance mode or if you went into full decline.

If you went into maintenance mode, we kind of estimate you'd lose from an oil percentage perspective, 1%, 1.5%.

We have another question from the line of Scott Hanold from RBC Capital Markets.

Really quickly, just to go back to the frac hits in the Howard County area.

When you step back and look at how you plan for in third quarter, was there any kind of miscommunication between you and the nonop that was fracking close to you?

Or was it just the amount of time it took for those wells to get online that was the delta?

Yes.

They fracked, I think, 24 wells; it took 2.5 months to get all 24 wells completed.

And I don't know if they had operational issues or not, but that was a long time to be pumping water in the ground immediately adjacent to some of our best oil producers in the county.

Yes.

So I guess to my -- the point I was trying to get to is, is there constant communication between you all when they're going to be close to you?

Or how does that operationally work when they're going to be fracking close to you?

And keeping in touch with them to understand where they're at and issues that they're having?

Yes, across the basin, we have good communications with all the operators.

And specifically, again, in Howard County.

Is -- those -- the big pad that was developed was physically adjacent to the lease line.

And so as they continue their development scenarios, they're moving further to the east, more away from -- away from our good producers.

So we think that -- again, we think we've got models more conservative on a go-forward basis and maintain good communication with all of our offset operators because we do the same to them.

So we treat them like we want to be treated.

Okay.

That's good to hear.

And my follow-up is, you mentioned in the press release talking about the -- how the mix of oil has changed prior -- since the closing of the Energen merger.

Anything with the GUR with the Energen assets?

Is that any different than what you would have expected at this point in time?

No.

It's just -- it's what we've expected.

We have another question from the line of Leo Mariani from KeyBanc.

I don't want to beat a dead horse on the issue here of third quarter kind of offset frac hits and sort of shut-ins.

But I was hoping to look at it slightly differently.

Would you guys be able to sort of quantify what you think you lost on production in third quarter, sort of relative to 2 quarter?

Was this kind of like a 2x or 3x standard deviation event versus what you normally would have seen in the prior few quarters?

Yes, I'd say the 2x standard deviation of that.

We traditionally model out good amount, 10% or so of gross production watered out, and this was closer to 15% to 20% for the quarter.

I estimate that it's probably an additional 4,000, 5,000 net oil barrels than what was expected going into the quarter.

Okay, that's helpful.

And just moving over to co-development.

Obviously, you guys talked about doing more zones that maybe you had in past years here in 2019.

Maybe just philosophically, can you talk a little about how you sort of think about that from a returns perspective?

Do you think that, that kind of hurts your returns a little bit, but maybe just gives you a lot more NPV and save costs in the longer term.

Maybe just talk about some of the trade-offs there.

Yes, let's just talk about the most germane one, which I believe is you see a potential based on way we have modeled the degradation of rate of return.

But that's offset because of the fact we're increasing net present value.

We believe if you don't catch some of these zones now that we've actually been really surprised at how good they've turned out.

If you don't catch them now, if you think you're going to come back in, in 5 to 6 years and get them, we've seen that, that's just not going to work.

I think Energen -- legacy Energen assets in Martin County, they did a lot of zone development and then came back in and did zones beneath it.

Using that data set and seeing the degradation of not doing them concurrently kind of emboldened us to make a strategy.

Our next question comes from the line of Michael Hall from Heikkinen Energy.

Leo just kind of hit on something I was going to ask, I guess, maybe coming out again a little bit.

Is it the parent well that has the degradation?

Or is it -- maybe parents not even right word, but is it the primary reservoir or the secondary reservoirs that have the degradation in performance if you come after it...

Yes, Michael, that's -- I said earlier that if you're trying to compare a Wolfcamp A well in Howard County, which is probably a 80% to 100% rate of return versus co-developing with it a Jo Mill or Middle Spraberry, which is probably a 35% to 50% rate of return, that's the delta that we're seeing.

Obviously, when we've made the decision to singularly develop the zones is really back in 2015 and 2016 when -- when oil price was in free fall, and we were trying to do the highest rate of return, highest rate of return zones.

And now we've seen that we believe the co-development is the right strategy on a go-forward basis.

Okay.

And it's kind of a use it or lose it, it sounds like, for the Tier 2 reservoirs, and it's those reservoirs that suffer, not the Tier 1 if you come back too late.

Is that right?

Yes, that's correct.

I mean I wouldn't say use it or lose it.

You just use it or you will have significant degradation in 7 -- 5, 7 years when you come back and try to get to secondary zones.

Okay.

That's helpful.

And then just circling back quickly on the San Pedro JV.

So is it right to think that -- I mean, the actual net CapEx this year -- sorry, in 2020 is just shy of 2.7 to 2.9 as opposed to 2.8 to 2.3.

Just trying to understand like how the actual cash impact will look for 2020, yes.

So really, it's net $140 million of less CapEx, but you probably get net $80 million or so less of production cash flow.

So on a free cash flow basis, you're getting $50 million to $60 million more of free cash flow.

Yes, okay.

So -- but the production guide is net.

Is that right?

The production guidance growth and the capital guidance growth.

There are no further questions at this time.

I will now turn the call back over to Mr. Travis Stice, the CEO.

Sir?

Thanks again to everyone participating in today's call.

If you have any questions, please contact us using the -- using the contact information provided.

We're in the office all the rest of this week.

This concludes today's conference call.

Everyone, thank you for joining us.

You have a good day.