Q3 2019 Earnings Call
Per day, ladies and gentlemen, unwelcome tickets I am ones like an I.T. saved quite things tend to 19 and names conference call. At this time all the participants line I you know he sent only mode. After the speakers presentation. There will be a question and answer session. If you have the question <unk> and the the number.
<unk> key on your touch tone telephone. He said question hasn't been <unk> are you wish to remove yourself from the Q.P. spread the hash Lucky I wouldn't mind. They these conferences being recorded Oh, no lights into this year host flights and he's gone, France, <unk> Vice President Investorrelations say you may be in the hall.
Thank you any good morning, and welcome to Downing back energies third quarter 2019 conference call.
During or call it able reference in updated investor presentation, which can be found on bikes website <unk>.
Representing diamond back today, a travesty I see in case, they went off C.F. up during this conference call. The participants may make certain forward looking statements relating to the company's financial condition results of operations plant objectives future performance in businesses because she knew that actual results could different materially from those are indicated in these forward looking statements do the variety of factor.
Information concerning these factors can be found on the company's problems with L.C.C. Additionally will make rough reference to certain on got measures. The reconciliations what the appropriate got measures can be found in our earnings release, if she'd yesterday afternoon, Oh now trying to call over to try the status.
Like you have them and welcome to Diamondbacks third quarter earnings call normally I jump right in and review key milestones and a quarter, but with a challenging market conditions I feel a 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.
<unk> nailed down over 25% year over year.
And we expect that downward trajectory to continue with frozen capital markets tighter lending conditions.
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 might potentially support all prices pending demand growth.
We believe these market conditions call for a 2020 investment framework, that's focused on flat today on capital spending.
And efficient low cost structure in returns on Capitol in excess of costs of capital all of which are strategies down and back 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 2000, a 19 year.
There was tremendous concern surrounding diamond backs ability to integrate the energy and acquisition and deliver on acquisition strategies.
Fundamental question was whether we can maintain or industry leading cause structure.
And capital efficiency on a company with twice the scale and double the people.
We also spoke of the significant shifted to consistently returning capital of the shareholders, while continuing to grow production.
And we sit ambitious targets for production growth in execution on operational efficiency.
Since then we've exceeded our own expectations of synergies realized from the energy transaction delivering on every synergy ahead of schedule.
I had a greater value to our shareholders, even creating a synergy score card updated quarterly since the transaction closed.
Transparently document our progress.
We have successfully taken or midstream entity rattler public raising over $700 million and proceeds in creating a hard margin high growth midstream subsidiary.
We have dropped down mineral assets from down the back in energy to Viper, increasing wipers exposure to down the back while receiving cash and stock in consideration.
We've executed on our grow improved strategy, but the vesting legacy energy and conventional properties for gross proceeds of 285 million.
We have realized and continue to realize operational efficiencies with average will cost today over 15% lower and diamondbacks costs prior to the energy in acquisition, leading industry and efficiency measures such as recycled ratio in demonstrating.
Strength of down with X. execution machine.
We've accomplished remarkable set of corporate objectives, while still deliberating on executionally cost measures.
These are the things that reflect on and considering down the backs performance during 2019.
Our businesses complex in this quarter, we had a number of anomalous advanced that caused several of the metrics we follow.
And or held accountable for the underperform our expectations.
We understand that the market monitors performance on a quarterly basis, which is why we have been asked transparent as possible.
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 it down and back.
After growing significantly for the first three quarters of the year Diamondbacks all production declined in third quarter due to the sale of 5800 barrels per day.
Low margin oil for more central by some platform has that effective July 1st 2019.
Without considering this effect diamond backs quarterly production group.
But the oil production decline.
The completion of 18 wells in our remote area and reach County, and 14 wells in Glasgow accounting five of which were ducks completed or drilled rather prior to the clothes near the energy and merger drove we'll cut down since these two areas begin production with all cuts below 65%. These three.
Only two wells made up over 35% of total gross wells completed in a third quarter versus 12% of the world's completed on the first half of the year and 15% of the wells there will be completed in the fourth quarter.
While we are accountable for forecasting our production.
Impact from offset completions were dramatic during the quarter. Another strong reminder, why we did not provide quarterly guidance.
Physically and Howard County, one of our most active and highest orkut fields, the combination of down and back for activity.
Offset operators, both to the east and west of our leasehold cut production in half or over 20000 gross barrels of won't per day during portions of the quarter.
While we'll plan to model. This in pack more conservatively going forward, we expect frack impacts to continue to be significant primarily in the middle <unk> with operators and fulfilled Multiwell pad development most.
Taking all isn't consideration along with current production levels, we expect fourth quarter 2019 or production to grow over 3% from the third core, but offset frack impact is still expected to be large and the fourth quarter.
<unk> Howard County, where this significant rig and completion activity due to the economics of the area.
Looking ahead to 2020 or goal and putting together our capital plan was to maximize or weighted production growth within a similar budget framework as detailed 19 getting more with less.
As a result, we expect to grow all production, 10% to 15% year over year incomplete over 10% more net lateral footage then 2019.
Most importantly, our budget assumes we cover our budget in base dividend above 45 dollar war and have over 675 million of pre dividend free cash flow with 55 dollar oil.
Or 2020 commodity price assumptions have weakened since our last communication around to 2020 free cash flow, which now seems $13 per barrel Ngos down almost 40% from me and $1.50 realize gas prices.
Regardless of the commodity price assumptions, we are committed to offering an industry, leading combination of growth and free cash flow yield and 2020.
We believe this capital operating plan reflects the optimal capital efficiency for achieving differential broken significant free cash flow and 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 or capital return program in reduce debt.
The biggest concern related to the Miss we experienced versus internal and street expectations in the third quarter and as a result, 2900 full year or production or one.
How can we be confident the oil production this and the third quarter is not the start of a continuing trend and to how the lessons learned from the third quarter accounted for the for guidance well first.
When there's a miss the magnitude that we just experienced and the third quarter, we have to fundamentally reexam on the assumption that lead that led to this performance we've done this.
And as a result with more conservatively modeled our expectations for the future, particularly external issues that are out of our control such as offset operator brackets like those experience and the third quarter.
Fulfill development by middle bass, and operators, including Diamondback increase the amount of production watered down on average throughout the course, the year, which was not modeled conservatively enough in 2119.
These are operational challenges not reservoir problems.
Second.
We had increased the amount of code development zones across more productive zones, which would begin in 2019, we expect to increase that in 2020, particularly in the middle inflation.
While this strategy expected to maximize the net present value and extends inventory life.
In some areas this capital allocation decision generates lower first year old production per developed pad.
Are middle bass and development plan prior to 2019 was predominantly focused on the Wolf campaign, the lower sprayberry.
In 2119 and carrying into 2020, we're increasing our exposure exposure to other zones, such as the Joe Middle Middle Sprayberry, and we'll can't be due to the improved well performance in these particular zones and the estimated net present value benefit of this code development.
This holds true to a lesser extent for the Delaware basin as well.
Where we have more second and third bones spring development plan, along with our primary development zone, the Wolf can't pay again.
This is a well mix issue not a reservoir problem.
Lastly, on a percentage basis, we're adding fewer new drill.
Hi, flushed volume wells in high all cut wells to the 2020 production mix than in previous years, which also lowers the corporate all makes you can see you know 2020, guys that were now got into oil only to address this confusion.
Well these changes in modeling assumptions in development strategy translate to an overall lower 2020, all production expectation relative to consensus.
Or 2020 capital efficiency will be slightly better than in 2019 due to execution improvements in lower costs structure as measured by drilling capital spent.
Barrel of oil production added.
After taking into account are over 36% oil base declined written 2020.
Our current capital forecast for 2020 incorporates today's service costs, which should decline from here opinion, a reduction unexpected bake some white activity levels.
As a result of all the data presented here I'm reiterating this is not an inflection point of course correction and the value proposition predominant back remains unchanged.
Comfortable double digital growth.
Mid single digit free cash flow yield and the lowest cost structure in the business today down the back is poised to grow production at the highest margin in capital efficiency in industry.
Maintaining a strong capital structure and activity and actively returning cash to shareholders with these comments complete operator, please open along for questions.
If you have a question. Please press this time.
Key on your touched on telephones.
Are you wish.
<unk>.
Tends to one question.
Your first question comes from the line often Neil Duignan Your line is open.
[noise].
Meanwhile, and Neil Good morning morning.
For 2020 oil and total production guidance suggest about 10% to 15% growth from that 19 midpoint, while still generating what I would assume around 5% free cash will 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 assume number of rigs and spreads in.
Joel RFS and LLS caused baked in there.
Yes, so I'll answer them and reverse the office costs, we just by doing what we actually saw a third quarter. So again as active level continues to slow down out here in the Permian. We expect has continued to see service cost reductions in an actual is going to provide a tailwind for our free cash flow generation.
Next year, I think specifically the risk in that we took on.
Brackets was more aggressively with more aggressively modeled this year than we did in 2019 and what that means is that you actually end up with a more subs a more severe hit across more wells said last longer but also when you look at the things that.
That.
That impacted the third quarter and how that adjusted some of our assumptions on a go forward basis, even the even down to the details of black how long it takes for well to recover once it's been watered out we've used 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 twin.
In the third quarter, but well look when you have a minutes of the.
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 same every single assumption that was made and we've done that I mean, we're down to we're looking at the daily increasing in your Hertz rate on sub pumps you know.
After frac.
Really we've really broke the business down into fundamental part so.
I think I think when you when you stub our toe like we did in the third quarter, you've got to be able to.
Adjust your future forecast to make sure that.
As you can hit those numbers and we've done so with the with the assumption. We we put in place I think the rig cadence and completion cadence you know the low end of our guidance probably is going to reflect a in order to if we hit that low in it would probably be a function of slowing down activity and the high end of the guidance is probably a function of.
Segments ammonium certainly no segments ammonium and maybe getting a couple of more wells drilled drilled and completed during the year.
Got it got it and then lastly can you speak to slide six senior debt, particularly the part a up on top that you talked about and you get this little then 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 how 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.
Quite assets that we can do more with under our execution and cost structure than others can.
But it does reflect the you know 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.
Very good thanks for the details.
We do have another question from the line of Bryan singer from Goldman Sachs. Your line is open.
Great. Thank you good morning.
Hey, Brian .
To follow up on a couple of comments you mentioned first can you add a little bit more color on the frac hit impact to that that you're forecasting for next year, and how that 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 it 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 how that leads to a declining or how that leads to an evolving decline rate.
And in both basis.
Yes, so specific it's it's it you know weve.
As we've done the forecast in 20, Twond and 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 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.
Oh.
And we've done that in each in each of the areas now again, what we've seen is they do return to peak production.
And so that's why make to commented it's not a reservoir issue because you are the area under the curve remains unchanged. It's now the delivery of that a better you are is a has been more conservatively models or you know with with respect to these brackets and I'd say, Brian on top of that we've been modeling frac hits for.
Our long time in Spanish trail in this case Q2, sorry, Q3 was extraordinarily difficult in Howard County, because of the size of the pads offset US right. Traditionally we've completed four well pads. So these device. There is a 24 well pad completed and that Frac spread was on site for two and half months and so thats a.
Significant hit even higher than what we originally expected so that that particular field. The Howard County field was hit by about 12000 gross barrels of oil a day for the whole quarter, which on a net basis is about 8000 net barrels a day.
Just to add to that I'll, just add to that Brian when you look at what we've been doing in Spanish trail now for over five years, we've seen the impact of of.
All of of Frac kids and in our comfort or confident that you know because of that experience. We've seen full recovery and not just the first time hit it some of these wells in Spanish trail have been hit multiple times, but each time that return back to their previous forecast.
Great. Thanks, 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 it kind of highlighted what the scenario would be at the at the higher end of the arrangement.
Centrally if you're investing.
At the midpoint of your Capex guidance, what do you see as the risk to both the downside any upside to the to that oil production guidance that you put out.
Yes, certainly the things that impacted us in the third quarter. We believe we've addressed those you know more aggressively or more conservative in the former forward guidance.
To spend the same capex next year or the midpoint of the Capex and come in at the low point, we will guide than you've Gotta have something you know you've got to have a poor well performance. You know that's that we're not expecting right now and we've not guided that direction, Paul as I said.
The the low end of the guide is more a function of you know.
Lower lower total activity.
Great. Thank you.
We do have another question from the line up.
From Stifel. Your line is open.
Thanks, Good morning all.
Hey, good morning dirt.
Perhaps for Travis or cases, we look at the 2020 capital program are there any quarters that have outsized activity in glasscock of or May of next year.
Yeah, I think I think the quarters again, we've learnt we've learned of what Weve of what we what we saw in the in the third quarter. This year and so the guidance that we put in place reflects.
A more steady diet.
Oh Romeo in Glasscock County wells on a quarter over quarter basis.
Great and perhaps for my follow up referencing slide seven 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, I mean, that's all all dependent upon activity right I mean at the same activity level cash flow. It's still grow in 2021, you know I don't I don't think it would grow 11% to 15%, but you still see growth. We feel like we have a lot of tailwinds going into next year, particularly no 10 for.
Better realizations on the oil side for the year, we've got some elouise tailwinds were always going to be declining throughout the year next year. So now that all supports a lower breakeven.
As we as we continue to grow but but don't continue to spend every dollar we make back in the ground to a two to fund that growth and <expletive> I just want to add since you brought up slide seven when you look at the the $55 oil Bart's a $675 as I said in my prepared remarks, we we'd originally communicated 700 fit.
$80 million of free cash flow at $55 oil.
But the deterioration of Ngls no that right now 13 Bucks a barrel, we lost seven bucks a barrel relative to our last communication and that's about $100 million were to 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 Rins Fine from Oppenheimer. Your line is open.
Hi, Good morning folks I had an organizational question, which perhaps is best suited for Travis.
In the last year, Dynavax closing Energen acquisition, Dave IPO It another subsidiary and add it organizations lost its COO in September I know dilutive action organization that some prided itself on running lean when there's a laser focus on DNA.
But I guess my question Travis is with your organizations complexity and the Threeq you mess that we saw last night on is the organization to lean are you right size to kind of execute like like you want it to and should investors be concerned about the complexity.
No complexity is part of our a fundamental DNA what looks complex to our investors, we intend to Mike look simple and you know organizationally I've said I think in the last earnings call I said, we're probably 150 people short.
And we're probably still you know somewhere around 100 100 people short and that's across you know every aspect of our business, but I'm not going to stand here and say that the function of third quarter was the result of one either complexity or to lack of people that you know we own it and that's what you expect me to do is to staff there.
Organization.
Adequately and to simplify complexity and that's what I intend to do.
Every day.
Okay, Okay, but thanks for that and I guess as my follow up eight prepared comments.
You on you talked about kind of that well mix issue from more zones in kind of your pad development can you talk about why your went well goes down is that a controlled flowback issue or is it because it will cuts and in other zones.
Yeah no. The all the all goes down you know on a year over year basis, because when you add in a Jo mill or middle Spraberry well into a.
For Zone development, you know it has a different oil delivery type curve than does the.
The wolfcamp, a or the lower spraberry, which weve.
Historically, you know had a a heavier dose of.
Those two developments zones. So when you look at the oil relative you know for four zone, where I've added in the Jo mill in the Middle Spraberry.
You see a you see that you see the corresponding impact.
Okay. Thank you.
[noise].
We do have another question from the line often Jeff.
Line is open.
I guess, I'm, probably going there and <unk> it looks like the other three Q, Delaware well costs are already at kind of the low end of your 2020 budgeted cost there, but just wondering is that I guess, a walmex consideration that may be drove three Q lower or do you think a is it fair to think that maybe there are some.
Got it conservatism in what you guys are assuming budget wise for for 2020.
Yes, Jeff for me how is the cheapest of the three fields in the Delaware Basin from a D.C. any perspective. So we did have lot of for May how wells come through in the third quarter, which is why that number looks low relative to the guide, but nice try to said.
You know, we're not guiding to service cost reductions from where we are today, we certainly expect to continue to see some some deflation and continue to get some efficiencies, but for the third quarter relative to 2020 really that's more a higher percentage of or may how rolling through the the capital side, yeah listen as a as our prepared for this quarter. We go through our.
You know our normal quarterly a quarterly review process, where we.
Do a well by well analysis of wells contributed in the quarter and like I couldn't be more proud of the continued focus laser like focus will be operations organization on.
Driving costs out and improving recovery so.
That part of our DNA is.
His spectacularly in place and and it's something up 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 your Travis can you talk about why 10% to 15% is the right growth for Diamond back in 2020 versus you know evaluating maybe trade offs of slower growth and more free cash flow to fund the buyback and maybe dividends.
Growth and just kind of how you guys evaluated the potential trade offs of those types of scenarios.
You know, it's it's not a a you know it's not a precise calculus granted but we had to balances you know we're trying to and we believe we have.
Presented a or a business model that has this kinda sustainable free cash flow I.
I want to go forward basis, and so you know if we if we had lower growth and greater cash flow and you know and 2020.
Then then you're going to you're going to impact the out years or your development plan. So.
Well, we believe we've done it struck what is an appropriate balance of maintaining them sustaining.
The free cash flow generation that this machines capable of.
What about the same time, you know kind of at the upper end of anybody out there in terms of production growth and listen I still believe.
No that down back or is the best execute or in the lowest cost producer, we should grow and though and Thats what weve presented in the 2020 Guy.
All right understood and appreciate the transparent prepared remarks drops.
You bet. Thanks.
Our next question from the line.
Ian tied up from Simons and then <unk> Your line is open.
<unk>.
Good. Thanks, maybe one more follow up on the co development strategy to the shift towards more co development next you have any impact on the way that you approach facility design or construction.
Or even on operating costs.
Yeah, no not really I still expect facility costs and operating cost a two to the decline year over year quarter over quarter, but that's part of my that's part of my prediction disposition, though but the co development or whether the you know the only thing that could possibly impact that would be as if we've added like in the.
Delaware, you know a higher percentage of of a second bone third bone springs wells that have a higher oil or higher water cut and will not have to adjusted but weve accounted for all of that.
Facilities design.
2020 go yeah, Ryan pad sizes and 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 Belo we over the long term.
Okay, Great. That's helpful. Thanks, and then.
Maybe just a.
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 entertain the idea at all of a.
Variable distribution in excess of a base dividend rather than a buyback.
Yeah, I think a if you go back and look at the previous communications that we've had about what our primary former returned to shareholders is and that's it that's in the form of the of an increasing dividend and that's what we intend to do on a go forward basis.
Variable distribution something that's not that's really not something we've considered you know we don't want to overly complicated 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 former 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 where we intend to do.
Okay. Thanks Travis.
<unk>.
We do have another question from the line of drew Venker from Morgan Stanley . Your line is open.
Hi, everyone. Just wanted to follow up on on the guidance for 2020, hoping you could give us a sense and very simple terms, how much downtime you're assuming all of your base production for 2020, and if you can compare that to what had assumed for the rich I'll 2019 guidance.
Yeah, I mean traditionally you know the base production, we assume you know high single digit downtime as a percentage of total six 7%.
Downtime that that number has stayed about the same for your base production what Weve rest is the additional production right. So you not not only are you dish your risking the new wells put online, but on top of that via the the data we have we shot in offset wells within a certain.
Perimeter of the while getting completed ahead of time. So you know 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 parameters certain diameter of the level that you're completing.
For a certain period of time.
Okay, but presumably you could still have us not watering out or shut it in impact from.
New wells on offset operators that would impact here your base production or my thinking about that incorrectly.
Communication between us and offset operators is important I think in the Midland basin, particularly where overall really close to each other and there is not big fields. That's important but you know we model that impacts.
Some conservatism and we also.
No were those guys are our operating we have a view into their six month frac schedules, we take that into account I think what happened here is you had a larger pad you know on watering us out for a longer period of time than originally expected and therefore going forward and those fields, where we have offset operators.
Were very conservative on the water out piece there.
Okay.
I think just <unk> I just to wrap that up I mean, we've got the visibility in you know you know we believe we've got you know more data analytics driven decisions or data analytics now they can increase the predictability is effect and weve accounted for that and it's it's in or a and it's in our and our go forward plan probably more so in this year's plans and then any plan.
Previously submitted.
Understood. Thanks, Travis I guess is valve as it thinking about 2020 and the transition over all to.
I think bigger projects on an average how you're thinking about the cadence of growth throughout 2020 is there a pretty wide range of project size and timing that what effect. It came to grow throughout the area could just give some more color on.
Yeah, not too much drew you know project side isn't changing much I'd say the type of wells within the project is changing right. So Midland Basin, we still do you know four or five six well pads or but theres more co development between zones. On so you know from a production growth perspective, you know, we you know we're going to get back.
To growth in the fourth quarter and grow fairly consistently through the first the first half of 2020 point and you know, there's not a big lumpy month or big lumpy quarter in that assessment is gonna be consistent pop growth and ER and production growth.
And then similar growth in the second half the or you think still consistent.
Yeah for Tony.
Thanks.
We haven't had a question from the line of Asit Sen from Bank of America. Your line is open.
Thanks. Good morning, Thanks for the details on the Frac hits, you provided to quantify in Threeq you could you I'm keys broadly.
Quantified the impact of Frac hits that you're assuming into 3% sequential growth in Fourq you.
Yes. It you know traditionally we model about 8% to 10% of our total production being watered out on any and in any given time I think as you think about the fourth quarter. Howard County is coming back you know today that fields to back up to 40000 gross barrels a day from the bottom of 25.
But you are watering out other areas, such Spanish trail, and small stuff and take us.
But on the overall basis, I'd say as a percentage of total production our frac it will be lower in Q4 than it was in Q3.
And pretty consistent through through 2020, especially as you get to fulfill development.
In the Midland Basin.
Okay, Great and then some of your peers of.
Showing strong results in the third bone spring and I'm. Just wondering if you have any incremental thoughts on that zone and the number of completions you're planning to.
Completing the zone I couldn't exactly figure it out and slide six but any rough estimation would be good.
Yeah, I think we're excited about it in the reward area and the female area as you get into our pay cuts County asked that we're more excited about second bone spring and the third bone spring. So while we're not as excited about the second bone and reward and and for me. How you know that's where the third bone is prevalent and then on the contrary in the paper.
Area, particularly on the eastern portion or western portion of the hate this area or the second bone is probably our secondaries on behind the Wolfcamp a.
Thanks, a lot.
We do have another question from the line Alpha Jeoffrey Lambujon from Tudor Pickering Holt your.
Your line is open.
Good morning, Thanks for taking my questions just a few follow ups on co development first one is as we look at the number of wells in zones like the Wolfcamp B, the middle Spraberry and the Jo mill on the Midland side, and third bone second bone on the Delaware side as a percent of total wells for the for the next year how's that percentage compared to.
To 29 teams mix and how does that change as you look forward to 2021 and beyond.
Yeah, Jeff I'll take the Delaware first you know because it's less of an impact and 29 team I'd say the Wolfcamp a was almost 90% of 2019 development and are in the Delaware basin going to closer to 85 or so in 2020 in the Midland Basin, you know the big move is actually actually happened in.
2019 versus 2018 2017, so you take 2018 in 2017 will 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 thoughts of that should we expect that percentage to continue kind of decreasing over time as you continue progressing on the on co developments.
Don't think it will decrease I think I think the shift has been made and we are getting well we believed to be all the economic zones at wants 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 in the Middle Spraberry for example versus what you've historically seen in the lower Spraberry Wolfcamp a.
Yeah. So very clearly you know 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 you know the lower Spraberry and you know between the Wolfcamp, a and the Wolfcamp B Wolfcamp. A is just so strong you know they have a similar to <unk> production profile between the two wolfcamp zones, but where we are.
You know the B is not as good as the AG, but still no highly economic so you have high early time production is just not as high as what you see animal campaign.
Thank you.
We do have another question from the line of David Deckelbaum from Cowen Your line is open.
Good morning, Travis Encase, Thanks for taking my questions guys.
You bet David.
I was hoping to get some color you talked a lot about 20 guidance.
You laid out that free cash projection of 675.
Counting for the lower NGL prices.
Can you add more color on just the Carlyle JV, the 15 to 17 wells being drilled one one where that developments taking place and to what you think the net cash benefits going to be two diamond back this year.
Yeah, David So this is the first year, where the where the Carlyle JV is that a significant portion of our total well count 16 wells about 5% of.
2020, total well count you know that's in the San Pedro Ranch, which is the south southeast corner of our hedges County asset.
You know Carlyle and Don back if elected to drill out and 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 and 2020 actually produces $50 million more free cash flow.
And then we're presenting on a on slide seven so we're putting up 15% of capital for 20% of the production.
And after certain return thresholds are met a we will control 85% of the production.
Okay. That's helpful.
The other question I was just you know you all made a lot of headway. This year in terms of Bella we are coming down.
Sounds like you have some infrastructure investments that you're hoping will pay off to similar effects and 20.
The margins that you're assuming I guess and 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 of times of how you're going into the fourth quarter and into 20 2020 on the L. We side. So you know we're kind of modeling mid fours for for Ela Lee going forward, but you know every time counts one cents is a million dollars a 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 color guys.
Thank you Dan.
[noise], we have another question from the line of frenzy sign that long way.
From Imperial capital your line is open.
Good morning, guys just that one question as you think about the free cash flow you talk about 2020, where does reducing the debt on the credit facility kind of come into that equation.
You look at asset sales and things are is that something that kind of normal course business alongside the other initiatives.
Yeah, Jason you know, we feel like we've got the revolver to a point, where we're comfortable yeah. 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, it's closer to five and a half billion.
You know we were trying to run this company like an investment grade company and we hope that time comps.
And at that point, we would reduce our revolver borrowings to zero and term out our our debt, but from an absolute basis, you know other things to be at the margin certainly, but we feel really comfortable about our growth profile and what are you know absolute leverage and leverage metrics look like.
I appreciate it thank you.
Thank you Jason.
I request on price.
I had question from the line up there at the time from Credit Suisse. Your line is open.
Thank you. Good morning. Appreciate your comments earlier about showing steady production grows cadence do Tony Tony I was wondering if you could give us some type of range, where oil production could be enough work you 2020.
Yeah, Ben I'm, hoping we you know we exit the year in the mid to high teens.
Exit to exit versus Q4 2019.
Got it and then that's looking 19 level would be sort out you know one nineties.
Yes.
All right close to mid Twentys.
So for Q.
Yeah, I mean, I think we tried to very accurately describe what we think Q4 2019 is going to look like and.
And that kind of growth rate on top of that.
Great. Thank you for that and then follow up was on a.
Buyback, how you guys thinking about pace of buyback going forward on what are more likely follow the quarterly free cash flow cadence throughout a year or would it be pretty opt for opportunistic depending on price actions.
Yeah, primarily it'll be based on on free cash flow and being revolver neutral I certainly think we have an opportunity here to be a little more aggressive on the near term, but over the long term. It's 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 bye.
We have done your questions on the line off I read tied to list from capital One Securities. Your line is open.
Thanks, Good morning try that one of this is when you look at the oil mix projected for 2020, I guess, it's down a couple of percent from where you were saying the first half of this year.
How do you how do you see the oil mix trending over the next several years, assuming no no additional acquisitions does it move closer to the one P. reserve number.
Yeah, ultimately will move closer to the one pin number but for the next couple of years I think what we've got model, but this kind of activity pace and you know that balance of kind of.
Growth in yield you know you I think you'll see more of a steady oil cut down on a go forward years on a yearly basis on a yearly basis. Yeah. Okay. Thank you and just lastly, shifting over to the line like prospect sounds like you you had some appraisal drilling in the past cool.
What are what are your thoughts on what you saw there and how many wells might be plan for 2020.
Yeah, We certainly would you know we didnt disclose any results this quarter, but though we like what we saw and we've got another pros or will they planned plan to.
Back after this year or back half of next year. Okay. Alright, that's all for me. Thank you.
We have another question from the line Charles I mean from Johnson Rice. Your line is open.
Good morning, Jarvis do you team you guys have covered a lot of ground already this morning, I think I've just couple of quick ones first one on on the tomato area.
I understand that that's a relatively a gas here, but but I think out its most of my understanding that that's one of your are these has been one of your best most attractive areas at the top of the portfolio is is that still the case or is it been anything it will still the case it.
Okay. Okay.
Thank you.
And then and then second this is up this is maybe a bit bigger bigger picture question Travis about about the service environment you in a lot of other operators are talking about service just you know deflation service cost but.
From the outside <unk> looking into certainly see this with their stock prices that looks like up like a sick or you know that sick business model that that's not doing very well so.
Do you guys ever do you get spent any time thinking or we're talking about the the viability Oh, There's your service partners and is that something that that you have anything you'd want to share your thoughts on.
Yeah look we need that sector took the to perform well their business partners and their vitally important to us prosecuting our development plan on a go forward basis.
No I believe that the headwinds the you know the upstream and be guys are facing or you are also being you know applied to the to the service sector, but.
I don't concern myself with viability as much as I do maybe availability you know there could be some so some elements of a deal with us sector that it gets put under more harsh fresher than than some of the big guys and that's that's why we try to be open and transparent with our service sector business partners to make sure that they understand.
Plans, we understand their plans.
Thanks Travis.
You bet. Thanks Charles.
We have another question from the line also beat you Sanchez from Susquehanna. Your line is open.
Hi, Thanks, good morning.
So I just wouldn't even looking at the Frac hits and the impact.
When you look at how quickly those wells can recover.
What do you shouldn't relationship between the the vintage if that well the producing well on the formations and <unk>, how should we think about that.
No I don't think vintage is is the is the relevant indicator you know it's just it's just proximity secure within a certain amount of lateral feet from that that particular, well you know we shut in or the while we're producing early and then it comes back a you know five to 10 days after that the Frac jobs.
Please yeah, we've got wells I think I mentioned earlier, we'd go Wills and Spanish trail that have been what Danny Frac, It five or six times over the last five or six years and.
As we go through and sit down with a reserve auditors you see you know you see the Frac. It and then you see the recovery back to the former decline right. So it's certainly than having to do the vintage. It just really has to do the proximity of worthy offending.
Know waters being injected a in the Frac operations.
Got it.
And then just getting back to that.
On.
The oil mix.
[laughter] see fueling that maintenance mode that youve referenced in in the press release the 1.7.
[noise] billing capex scenario.
Not that that's what you're doing but if thats the case sort of we better understand.
The.
Impact on fresh loss coming on what were the.
The oil mix line out.
Yeah, So oil oil decline base decline is 30, 637% next year, Yeah, we based climbs 33%. So you will see you know 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 wanted to maintenance mode. We kind of estimate you lose.
Well percentage perspective, you know per cent for second half.
Okay. That's that's very helpful. Thank you.
Thank you could you.
We have another question from the line of <unk> <unk> from RBC capital markets. Your line is open.
Thanks. Appreciate it you know really quickly you know just to go back to the a frac hits and the Howard County area.
When when you step back and look at you know how you plan for it in third quarter was was there any kind of miscommunication between you and the the a the the non up that there was a you know fracking close to you or was it just the amount of time. It took you know for those wells to a you know get online that was was the delta.
Yeah, you know that they frac that I think 24 wells it took a two and a half months to get all 24 wells completed.
And no moved ahead operational issues or not but that was along that was a long time to a you know to be pumping water underground immediately adjacent to some of our best best oil producers in the county.
Yes, so I guess Tonight, but the point I was trying to get too is you know there constant communication between your win win you know, they're gonna be close to you or how does that how does that operationally work when when you know they're going to be fracking close to you and no keeping in touch with them to understand where they're at in any issues that they are having.
Yeah across the basin, we have good good communications with all the operators and you know specifically get in Howard County.
As you know that those that that big pad that was developed was physically adjacent to lease lawn and so as they continue their development scenarios. There moving further to the east you know more way from a away from a for more good producers. So.
We think there again, we think we've got models you know more conservative they'll go on a go forward basis and maintain good communication with the with all were offset operators because we do the same to them. So we we treat doing what we want to be treated okay. That's good to hear in the in my follow up is is you mentioned in the press release talking about the how the mix.
Oils change you know you know prior years since the closing of the energy merger has is you know anything with the you know did you are with the energy now says 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.
Okay. Thank you.
We haven't had your question from the line after Leo Mariani from Keybanc. Your line is open.
Yes, Hi, guys don't want to beat a dead horse on the issue here, a third quarter kind of offset frac hits in in so we shut ins or but I was hoping to look at it slightly differently. What are you going to be able to sort of quantify what you think you lost on reaction in third quarter sort of relative.
Two quarter, a was just kinda like a two or three times standard deviation event versus what you normally had it would've seen a in the prior a few quarters.
Yeah, I'd say the two times standard deviation of that you know we traditionally model out you know good them out you know 10% herself gross production watered out and this was you know this was closer to 15 to 20 for the quarter.
Estimate that you know probably an additional four or 5000 net oil barrels and then what was expected going into the quarter.
Okay. That's helpful and just moving over to co development. Obviously, you guys talked about a you know doing a you know more zones are than maybe you had in past years here.
2019, maybe just philosophically can you talk about how you sort of think about that somewhere returns perspective, do you think that that kind of hurts your returns a little bit, but maybe just a gives you a lot more NPV and stayed constant longer term, maybe just talk about some of the trade offs. There yeah, let's just talk about the most germain one which I buy.
Believed as you know you see you see a potential based on where we have a model the degradation of in a of ready to return, but that's offset because in 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 get your now if you did you think you're going to come back in and five to six years.
And did well we've seen that that's just not going to work I think a energen legacy energen assets a in Martin County, you know they they did a lot of a lot of zone development and then came back in into Jones beneath it and using that data set and seeing the degradation you know if not doing them concurrently.
Kind of embolden, there's two to make this strategy.
Thank you.
Our next question comes from the line of Michael Hall from.
Second in energy your line is open.
Thanks.
Just kind of hit on something I was going to ask I guess, maybe coming out and again a little bit is it is it the parent well that has the degradation or is it.
Maybe parents, not even or anywhere but there is it is it the you know the primary reservoir or the secondary reservoirs that have the degradation in.
And performance fees come after it.
Yes, let's take a long dated said.
Yeah, I said earlier that you know if you're trying to compare.
No I'm, a wolfcamp, a well in Howard County, which is probably a 80% to 100% ready to return.
Versus a co developing with it you know Jo mill or middle Spraberry, which is probably.
35% to 50% ready to return.
That's that's the Delta that your that we're saying obviously, if we you know when we've made the decision to you know.
You know just 'cause singular developed a zones is really back in 2015 in 2016, when the when oil prices in free fall.
And we were trying to do the highest rate of return <unk> high grade return zones and now we've seen you know that we believe that co development is the is the right strategy on the go forward basis, Okay, and it's it's kinda use it or lose it it sounds like for the.
The tier two reservoirs and it's those reservoirs that suffer not the tier one if you come back to late that right. Yeah. That's correct them I wouldn't say use it or lose that he just a use it or you'll have significant degradation in 7757 years, when you come back and try to get the secondary zones.
That's helpful. And then just circling back quickly on the San Pedro JV. So <unk> is it right to think that the.
You mean, the actual net capex this year or sorry in 2020 is yeah, just shy of 2.7 to 2.9 as opposed to 2.8 to 2.3 I'm just trying to understand I hope so how the actual cash impacts will look for 2020.
Yeah, So really it's Matt you know $140 million of less Capex, but you probably get Matt you know 80 million or so less of production cash flow. So on a free cash flow basis, you're getting 50 to 60 million more of free cash flow.
Yeah, Okay, so, but the big production guidance net is that right.
Production guided gross in the and the and the capital guidance for production in Africa, Okay got it alright. Thank you.
They no further questions at this time I know tend to call back over to Mr. job is tight if you see.
Thanks, again to everyone participating in today's calls.
If you have any questions. Please contact is usually a confirmation or using the contact information provided we're in the office. So all the rest of this week.
<unk>.
This concludes today's conference call at me line. Thank you for John Yes, you have on the day.