Diamondback Energy, Inc.

Good day, ladies and gentlemen, and welcome to the Diamond Tech Energy 3rd Quarter 2019 Earnings Conference Call. At this time, all participants' lines are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. If you have a question, please press the star and the number 1 key on your touch-tone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the hash key. As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Adam Lawless, 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 Dye, CEO, and Kate Stantoff, 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 gap measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice.

Thank you, Adam, and welcome to Diamondback's third quarter earnings call. Normally, I jump right in and review key milestones in a quarter, but with the challenging market conditions, I feel the need to reflect on where we are today. Investors' 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 costs 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. 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 returning 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 at a 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 costs today over 15% lower than Diamondback's costs prior to the Energen acquisition, leading the 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 in 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 two 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 assets effective July 1, 2019. Without considering this effect, Diamondbacks' quarterly production grew, but the oil production declined. The completion of 18 wells in our Vermejo area in Reeves County and 14 wells in Glasgow County, five of which were ducts completed or drilled, rather, prior to the closing of the energy merger, drove oil cut down since these two 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 down and back frack activity and offset operators both to the east and west of our leasehold cut production in half for 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 frack impacts to continue to be significant primarily in the Midland Basin with operators in full-filled 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 percent year over year and complete over 10 percent 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 pre-dividend 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 four 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 frack hits, like those experienced in the third quarter. Full field development by Midland Basin operators, including Diamondback, increased the amount of production watered 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've 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 Wolf Camp A and the Lower Sprayberry. In 2019 and carrying into 2020, we're increasing our exposure to other zones, such as the Joe Mill, Middle Sprayberry, and Wolf Camp 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, the Wolf Camp 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 in capital efficiency in the industry while maintaining a strong capital structure and activity in actively returning cash to shareholders. With these comments complete, operator, please open the line for questions.

Ladies and gentlemen, if you have a question, please press the star and then the number one key on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the hash key. Please limit your questions to one question and one follow-up. Your first question comes from the line of Neil Dingman. Your line is open.

Good morning, Neil.

Good morning, morning. Your 2020 oil and total production guidance suggests about 10% to 15% growth from 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 earlier. how you risk this, and then the assumed number of rigs and spreads and, you know, potential OFS and LOS costs baked in there?

Yeah, so I'll answer them in reverse. The OFS costs, you know, we just baked in what we actually saw in the third quarter. So, again, as activity level continues to slow down out here in the Permian, we expect to continue to see service cost reductions, and that actually is going to provide a tailwind for our free cash flow generation next year. I think specifically the risking that we took on frack 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 last 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 you know, how long it takes for a well to recover once it's been watered out. You know, we've extended that time. You know, in the co-development of some of the zones we've talked about, we've extended the time to peak production, you know, 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, reexamine every single thing we've done and every single assumption that was made, and we've done that. I mean, we're down to, you know, we're looking at, you know, the daily increase in your hertz rate on sub pumps, you know, after frack. You know, we've really broke the business down into fundamental parts. So, you know, I think, you know, when you stub your toe like we did in the third quarter, you've got to be able to, you know, adjust your future forecast to make sure that, you know, that you can hit those numbers. And we've done so with the assumption we put in place. I think, you know, the rig cadence and completion cadence, you know, the low end of our guidance probably is going to reflect in order to, you know, if we hit that low end, it would probably be a function of slowing down activity. And the high end of the guidance is probably a function of, you know, saving some money and maybe getting a couple of more wells drilled and completed during the year.

Got it, got it. And then lastly, can you speak to slide six in your deck, particularly the part up on top there where you talk about, and you hit this a little bit on the prepared remarks, about the increased co-development between zones in the middle 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 how we think about the future. 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.

Very good. Thanks for the details.

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

Great. Thank you. Good morning. Hey, Brian. To follow up on a couple of the 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, you know, we see the impact when on the negative side to production. Can you talk about what happens when it goes away, how the wells respond, how quickly they get back, or if they get back to the production level 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?

Yeah, so specific, you know, it's, you know, we've 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 zero 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 two elements, the number of days that it produced zero 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 crackheads.

Yeah, and I'd say, Brian, on top of that, We've been modeling frack 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, you know, we've completed four-well pads. You know, to the east of us, there's a 24-well pad completed, and that frack spread was on site for two and a half 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 Trill now for over five years, we've seen the impact of frack hits. and are confident that because of that experience, we've seen full recovery. 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, thanks. You partially answered this just in the earlier question, but if we 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 in 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 out?

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 or the midpoint of the capex and come in 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. Great. Thank you.

We do have another question from the line of Derek Whitfield from Stifel. Your line is open.

Thanks. Good morning, all.

Hey, good morning, Derek.

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

Yeah, I think the quarters, you know, again, we've learned of what we saw in the third quarter this year. And so the guidance that we put in place reflects, you know, a more steady diet of Vermejo and Glasgow County wells on a quarter-over-quarter basis.

Great. And perhaps for my follow-up, referencing slide 7, your asset base is quite resilient at lower prices. Assuming lower girth in 2020, how would this slide look for 2021 in terms of your cash flow breakeven?

Yeah, Derek, I mean, that's all dependent upon activity, right? I mean, at the same activity level, cash flow would still grow in 2021. You know, I don't think it would grow 11% to 15%, but you'd still see growth. You know, we feel like we have a lot of tailwinds going into next year, particularly, you know, 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, you know, that all supports a lower break-even as we continue to grow, but don't continue to spend every dollar we make back in the ground to fund that growth.

And, Derek, I just want to add, since you brought up slide seven, when you look at the $55 oil bar, it says $675. As I said in my prepared remarks, you know, we had originally communicated $750 million of free cash flow at $55 oil. But the deterioration of NGLs, you know, 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.

Great. Thanks for your time, guys.

We do have another question from the line of Team Res Fund from Oppenheimer. Your line is open.

Good morning, folks. I had an organizational question, which perhaps is best suited for Travis. In the last year, Diamondbacks closed the Energen acquisition. They've IPO'd another subsidiary, and the organization's lost its COO in September. I know Diamondbacks 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 myths, that we saw last night. Is the organization too lean? Are you right-sized to kind of execute like you want it 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, you know, organizationally, I've said, I think in the last earnings call, I said we were 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, but thanks for that. 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 one oil goes down? Is that a controlled flowback issue, or is it because of oil cuts in other zones?

I'll leave it there. Yeah, no, the oil goes down, you know, on a year-over-year basis because when you add in a Joe Mill or a Middle Sprayberry well into a, four-zone development, you know, it has a different oil delivery type curve than does the Wolf Camp A or the lower spray berry, which we've, you know, historically, you know, had a heavier dose of those two development zones. So when you look at the oil relative, you know, for a four-zone where I've added in Joe Mill and the middle spray berry, you know, you see the corresponding impact.

Okay. Thank you.

We do have another question from the line of Jeff Grump. Your line is open.

Jeff Grump I guess wondering, it looks like the 3Q Delaware well costs are already at kind of the low end of your 2020 budgeted costs there. We're 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, you know, embedded conservatism in what you guys are assuming budget wise for 2020?

Yeah, Jeff, you know, Vermejo is the cheapest of the three fields in the Delaware Basin from a D, C, and 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, you know, as Travis said, you know, 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 our maho rolling through the capital side.

Yeah, listen, as I prepare for this quarter, we go through our normal quarterly review process where we do a well-by-well analysis of wells that were contributed in the quarter. And I couldn't be more proud of the continued focus, laser-like focus of the operations organization on driving costs out and improving recovery. So that part of our DNA is... is spectacularly in place, and it's something I monitor almost on a daily basis.

Got it. Understood. Thanks for those comments. 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.

Yeah, you know, it's not a precise calculus, granted, but what we had to balance is, you know, we're trying to, and we believe we have, presented a business model that has this kind of sustainable free cash flow, you know, on a go-forward basis. And so, you know, if we had lower growth and greater cash flow, you know, 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. We should grow. And that's what we've presented in the 2020 guide.

All right. Understood and appreciate the transparent prepared remarks, Travis.

You bet. Thanks, Jim.

Our next question from the line of Ryan Todd from Simon's Energy. Your line is open.

Good. Thanks. Maybe one more follow-up on the co-development strategy. Does the shift towards more co-development next year have any impact on the way that you approach facility design or construction or even on operating costs?

Yeah, not really. I still expect facility costs and operating costs to decline year over year, quarter over quarter, but that's part of my predisposition, though. But the co-development, whether the You know, the only thing that could possibly impact that would be is if we added, like in the Delaware, you know, a higher percentage of second bone, third bone springs wells that have a higher water cut and we might have to adjust it. But we've accounted for all of that facilities design in our 2020 guidance.

Ryan, pad size isn't 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 one-time expenses that should roll through in 2020 and help LOE over the long term.

Okay, great. That's helpful. Thanks. 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?

Yeah, 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 in the form of an increase in dividend, and that's what we intended to do on a go-forward basis. You know, the variable distribution, that's really not something we've considered. You know, 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, you know, potential for, you know, as we said, we're always going to increase the dividend on a go-forward basis. And that's what we intend to do.

Thanks, Travis.

We do have another question from the line of Drew Benker from Morgan Stanley. Your line is open.

Hi, everyone. 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.

Yeah, Drew, I mean, traditionally, you know, the base production, we assume, you know, high single-digit downtime is a percentage of total, you know, 6%, 7% downtime. You know, that number has stayed about the same, you know, for your base production. What we've risked is, you know, 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 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?

Yeah, communication between us and offset operators is important. You know, I think in the Midland Basin particularly where, you know, we're all really close to each other and there's not big fields, that's important. But, you know, we model that impact via some conservatism. And we also know where those guys are operating. We have a view into their six-month track schedule, so we take that into account. I think what happened here is you had a larger pad 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. OK.

I think just to wrap that up, I mean, we've got the visibility and, you know, we believe we've got, you know, more data analytics-driven decisions or 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. Thanks for that, Travis. I guess as developers think about 2020 and the transition overall to, I think, bigger projects on average, how do you guys think about the cadence of growth throughout 2020? Is there a pretty wide range of project sizes and timing that would affect the cadence of growth throughout the year, or you could just give some more color on that?

Yeah, not too much, Drew. You know, project size isn't changing much. I'd say the type of wells within the project is changing, right? So Midland Basin, you know, we still do you know, four, five, six well pads, but there's more co-development between zones. And so, you know, from a production growth perspective, you know, we are going to get back to growth in the fourth quarter and grow fairly consistently, you know, through the first half of 2020. And, you know, there's not a big lumpy month or a big lumpy quarter in that assessment. You know, it's just going to be consistent pop growth and production growth.

And then similar growth in the second half of the year, you think, is still consistent? Yeah. Second half of 20? Thanks.

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

Thanks. Good morning. Thanks for the details on the frack hits you provided to quantify in 3Q. Could you, Case, broadly quantify the impact of frack hits that you're assuming in the 3% sequential growth in 4Q?

Yeah, I said, you know, traditionally, you know, we model about 8% to 10% of our total production being watered out at any given time. I think as you think about the fourth quarter, Howard County is coming back. You know, today that fields 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 as a percentage of total production, our frack hit will be lower in Q4 than it was in Q3 and pretty consistent through 2020, especially as you get to full field development in the Midland Basin.

Okay, great. And then some of your peers are showing strong results in the third 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 six, but any rough estimation would be good.

Yeah, 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 than 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 Pegas area, the second bone is probably our secondary zone behind the Wolf Camp Bay.

Thanks a lot.

We do have another question from the line of Joffrey Lampudon from Tutor Pickering Hold Company. Your line is open.

Good morning. Thanks for taking my questions. Just a few follow-ups on co-development. First one is, you know, as we look at the number of wells and zones like the Wolf Can't Be, the Middle Sprayberry, and the Joe Mill, on the Midland side and the Third Bone and Second Bone on the Delaware side, as a percent of total wells for the next year, how does that percentage compare to 2019's mix, and how does that change as you look forward to 2021 and beyond?

Yeah, Jeff, you know, I'll take the Delaware first, you know, because it's less of an impact. In 2019, I'd say the Wolf Camp Bay was, you know, almost 90% of 2019 development in the Delaware Basin, going to closer to 85 or so in 2020. In the Midland Basin, you know, the big move actually happened in 2019 versus 2018, 2017. So, you know, you take 2018 and 2017, we're probably closer to 65 to 70%. Wolf Camp Bay and Lower Sprayberry versus 2019 and 2020, you know, closer to 50% or 55% in the Wolf Camp Bay and the Lower Sprayberry.

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'll decrease. I think the shift has been made, and, you know, 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 Wolf Camp B in the middle spray berry, for example, versus what you've historically seen in the lower spray berry in the Wolf Camp A?

Yeah, so very clearly, you know, the middle spray berry takes longer to clean up, so you do have less production early time in the middle spray berry in the gel mill versus, you know, the lower spray berry. And between the Wolf Camp A and the Wolf Camp B, the Wolf Camp A is just so strong. They have a similar production profile between the two Wolf Camp zones, but where we are, the B is not as good as the A, but still highly economic. So you have high early time production. It's just not as high as what you see in the Wolf Camp A. Thank you.

We do have another question from the line of David Zeckelblum from Cohen. Your line is open.

Good morning, Travis and Case. Thanks for taking my questions, guys.

You bet, David.

I was hoping to get some color. You talked a lot about the 20 guidance. You laid out that free cash projection of 675 accounting for the lower NGL prices. Can you add more color on just the Carlisle JV, the 15 to 17 wells being drilled, one where that development is taking place? And then two, what you think the net cash benefit's going to be to Diamondback this year?

Yeah, David, so this is the first year where the Carlisle JV is a significant portion of our total well count. You know, 16 wells, about 5% of 2020 total well count. You know, that's in the San Pedro Ranch, which is the southeast corner of our Pegas County asset. You know, Carlisle 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 than we're presenting on slide seven. 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 know, 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 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?

You know, 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, you know, we're kind of modeling mid-fours for LOE going forward. But, you know, every cent counts. You know, one cent is a million dollars 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.

Appreciate the call, guys.

Thank you, Sandy.

We have another question from the line of Jason Wongler from Imperial Capital. Your line is open.

Good morning, guys. Just had one 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 things or is that something that's kind of normal course of business alongside the other initiatives?

Yeah, 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 energy and properties, which had a borrowing base of $2 billion. So our pro forma borrowing base is closer to $5.5 billion. We're 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 zero and term out our debt. But from an absolute basis, you know, other things to do at the margin, certainly, but we feel really comfortable about our growth profile and what our, you know, absolute leverage and leverage metrics look like.

I appreciate it. Thank you.

Thank you, Jason.

Our request, our first, our question from the line of Betty John from Credit Suisse. Your line is open.

Thank you. Good morning. 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 the 4Q 2020?

Yeah, 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 4Q19 level will be sort of in the low 190s, so that will put us in probably close to mid-220s for 4Q?

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

Great. Thank you for that. 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?

Yeah, 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.

Got it. Makes sense. That's all for me. Thanks.

Thank you, Betty.

We have another question from the line of Richard Tulis from Capital One Securities. Your line is open.

Thanks. Good morning. 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?

Ultimately, it will 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 growth and yield, I think you'll see more of a steady growth oil cut, you know, on the go forward years. On a yearly basis? On a yearly basis, yeah.

Okay, thank you. And just lastly, shifting over to the limelight prospect, sounds like you had some appraisal drilling in the past quarter. You know, what are your thoughts on what you saw there and how many wells might be planned for 2020?

Yeah, we certainly, you know, we didn't disclose any results this quarter, but we like what we saw and we've got another appraisal well We plan to back after this year or back after next year.

Okay. All right. That's all from me. Thank you.

We have another question from the line of Charles Amid from Johnson Rice. Your line is open.

Good morning, Travis, to you and your team. 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 a gassy area, 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 that's changed there? Still the case. Okay, got it. Thank you. 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 a service, you know, deflation service cost. 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 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?

Yeah, 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. You know, I believe that the headwinds the upstream E&B guys are facing are also being applied to the service sector. But, you know, I don't concern myself with viability as much as I do maybe availability. You know, there could be some elements of the OFS sector that gets put under control you know, more harsh pressure than some of the big guys. And that's, you know, that's why we try to be open and transparent with our service sector business partners is to make sure that, you know, they understand our plans and we understand their plans.

Thanks, Travis.

You bet. Thanks, Charles.

We have another question from the line. Your line is open.

Hi, thanks. Good morning. Travis, when looking at the frack hits and impact, when you look at how quickly those wells can recover, is there a relationship between the vintage of that well, the producing well, the formations, and how should we think about that?

No, I don't think vintage is the relevant indicator. You know, it's just proximity. So if you're within a certain amount of lateral feet from that particular well, you know, we shut in the well we're producing early and then it comes back, you know, five to ten days after the frac job is complete.

Yeah, we've got wells, I think I mentioned earlier, we've got wells on Spanish Trail that have been, what, Danny, frac hit five or six times, you know, over the last five or six years. And, you know, as we go through and sit down with our reserve auditors, you see, you know, you see the frac hit and then you see the recovery back to the former decline rate. So, It certainly doesn't have anything to do with the vintage. It just really has to do with the proximity of 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, we better understand the impact on flush wells coming on. Where could the oil mix line out?

Yeah, so oil decline, base decline is 36%, 37% next year. VOE 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, you know, full decline. If you went into maintenance mode, we kind of estimate you lose, from a, well, percentage perspective, you know, a percent, percent and a half.

Okay, that's very helpful. Thank you.

Thank you, Biju.

We have another question from the line of Kat Hanold from RBC Capital Markets. Your line is open.

Thanks, appreciate it. You know, really quickly, you know, just to go back to the frack hits in the Howard County area, when you step back and look at, you know, how you planned for it in third quarter, was there any kind of miscommunication between you and the non-op that was, you know, fracking close to you, or was it just the amount of time it took, you know, for those wells to, you know, get online that was the delta?

Yeah, you know, the They fracked, I think, 24 wells. It took two and a half months to get all 24 wells completed. 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.

Yeah, so I guess to the point I was trying to get to is, you know, is there constant communication between you all when, you know, they're going to be close to you? Or how does that operationally work when, you know, they're going to be fracking close to you and, you know, keeping in touch with them to understand where they're at and issues that they're having?

Yeah, across the basin we have good communications with all the operators. And, you know, specifically, again, in Howard County is, you know, that 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, you know, more away from our good producers. So, you know, we think that, again, we think we've got to model, you know, more conservatively 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 how the mix of oils changed prior or since the closing of the energy merger. Anything with the GOR, with the energy and assets, is that any different than what you would have expected at this point in time?

No, it's just what we've expected. Okay, thank you.

We have another question from the line of Leo Mariani from KeyBank. Your line is open.

Hi, guys. I don't want to beat a dead horse on the issue here of third quarter kind of offset brackets 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 two-quarter? Was this kind of like a two- or three-time standard deviation event versus what you normally would have seen in the prior few quarters?

Yeah, I'd say it was a two-time standard deviation event. You know, we traditionally model out, you know, a good amount, you know, 10% or so of gross production watered out, and this was, you know, this was closer to 15 to 20 for the quarter. You know, I estimate that, you know, it was probably an additional 4,000 or 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 than maybe you had in past years here in 2019. Maybe just philosophically, can you talk a little bit 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 tradeoffs there.

Yeah, let's just talk about the most germane one, which I believe is, you know, you see a potential based on the way we have a model of 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 turned out. If you don't catch them now, if you think you're going to come back in in five to six years and get them, we've seen that that's just not going to work. I think legacy energy 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 this strategy.

Thank you.

Our next question comes from the line of Michael Hall from Hygiene and energy, your line is open.

Thanks. Leo just kind of hit on something I was going to ask. I guess maybe coming at it again a little bit. Is it the parent well that has the degradation, or is it the, well, maybe parent's not even the right word, but is it the primary reservoir or those secondary reservoirs that have the degradation in performance if you come after it? Yeah, Michael, that's a good question.

Yeah, I said earlier that if you're trying to compare a Wolf Camp A well in Howard County, which is probably an 80% to 100% rate of return, versus co-developing with it a Joe Mill or a Middle Sprayberry, which is probably a 35% to 50% rate of return, that's the delta that we're seeing. Obviously, if we... When we made the decision to singly develop the zones was really back in 2015 and 2016 when the oil price was in free fall. We were trying to do the highest rate of return zones, and now we've seen that we believe that co-development is the right strategy on a go-forward basis.

Okay. 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?

Yeah, that's correct. I mean, I wouldn't say use it or lose it. You just say use it or you'll have significant degradation in five, seven years when you come back and try to get the secondary zones.

Okay. That's helpful. And then just circling back quickly on the San Pedro JV, is it right to think that the I mean, the actual net capex this year, or sorry, in 2020 is just shy of 2.7 to 2.9 as opposed to 2.8 to 2.3. Just trying to understand how the actual cash impacts will look for 2020.

Yeah, 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, you know, 50 to 60 million more of free cash flow.

Yeah, okay. But the production guide is net, is that right?

The production guide is gross and the capital guide is gross.

The production is also gross. Okay, got it. All right. Thank you.

There are no further questions at this time. I will now turn the call back over to Mr. Travis Tice, the CEO. Sir?

Thanks again to everyone participating in today's calls. If you have any questions, please contact us 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.