Q3 2019 Earnings Call
Good morning, and welcome to Centennial Resource developments conference call to discuss its third quarter 2019 earnings today's call is being recorded a replay of the call will be accessible until November 19th 2019 by dialing 8558 fivenine to.
Euro five six and entering the conference I'd number 3066178 or by visiting Centennial's website at Www Dot C. D E B and C dot com.
At this time I would like to turn the call over to he's made <unk> centennial's director of Investor Relations for some opening remarks. Please go ahead.
Thank you Michael.
Thank you all for joining us on the company's third quarter 2019 earnings call.
Presenting on the call today Mark.
Our chairman and Chief Executive Officer.
George Goodness, our Chief Financial Officer.
And shown Smith, our Chief operating officer.
Yesterday November 4th we filed a form 8-K with an earnings release.
Porting quarterly earnings results for the company and operational results for subsidiary Centennial resource production LLC.
We also posted in earnings presentation to our website that we will reference during today's call.
You can find the presentation on our website homepage, we're under presentations.
Www dot ceded Inc. dotcom.
I would like to note that many of the comments. During this earnings call are forward looking statements that involve risk and uncertainties that could affect our actual results and plans.
Many of these risk or beyond our control nor discuss in more detail in the risk factors and forward looking statements sections, where filings with the FCC.
Including our annual report on Form 10-K for the year ended December 31st 2018.
Although we believe the expectations expressed or based on reasonable assumptions. They are not guarantees of future performance and actual results.
Excuse me actual results or developments may differ materially.
They also refer to non-GAAP financial measures that helped facilitate comparisons across periods and with our peers.
Pretty non-GAAP measure we use a reconciliation to the nearest corresponding GAAP measures can be found in our earnings release or presentation, which are both available on our website with that I'll turn the call over to Mark that doesn't chairman and CEO .
Thanks, Hey, good morning, welcome to Centennial second quarter earnings call.
Presentation sequence on this call will be as follows.
George will first discuss our quarterly financial results updated guidance and liquidity.
John will then provide an operational update including recently efficiencies will result, then I'll follow with my macro views current strategy emanating from the macro.
Now as George to review our financial results.
Thank you Mark Centennial's operations continued to perform well as we posted another good quarter.
As you can reference on slide 14 of the earnings presentation net oil production for the third quarter average slightly over 42000 barrels per day.
An average net oil equivalent production totaled approximately 76300 barrels per day, which was up approximately 17% and 21% respectively above the prior year period.
Revenues totaled approximately 229 million, which was a 6% decrease compared to Q2, primarily because of lower oil and NGL realizations.
Mid cush basis hedges negatively impacted our realized price by $3 per barrel on average for the quarter.
I'll note that the impact from our 2019 basis hedges is primarily a third quarter then it will decrease significantly in Q4.
Inclusive of basis hedges centennial's realized oil price was 40 871 per barrel for the quarter compared to 54 45 in Q2.
Shifting to unit costs, Kashi and am DDNA were essentially flat to the prior quarter.
<unk> dollar 81 per barrel in 16 of six respectively.
Hello, we increased to $6.03 per barrel as a result of higher electricity costs. During the month of August in addition to increase chemical and equipment costs.
GPM T. expensed increased to $2, a 97 cents per barrel due to lower reimbursements associated with the subleasing of our natural gas from transportation agreements. In addition to higher costs associated with our percent of proceeds processing contracts.
Finally, severance and AD valorem taxes were 5.3% of revenue compared to 7% in Q2.
As a result of our Q3 performance for the second consecutive quarter.
We are increasing production guidance.
Annual oil production guidance is being increased by 3% at the midpoint to 42250 Boe per day and total equivalent production guidance is being increased by 5% at the midpoint to 74750.
In total this represents an increase of our full year oil and total equivalent production growth targets from 18, and 17% respectively to 22%.
We're also increasing the midpoint of our completions guidance by five wells to 75 gross operated completions given the efficiencies seen to date.
Additionally, we are increasing the midpoint of Ela, we by 14% to $5.30 from $4.65 and a reducing DNA in cash DNA by three and 5% respectively.
Capital guidance remains consistent with the ranges we provided at the beginning of the year.
All of these changes are outlined on page 11 of the earnings presentation.
For the quarter, we recorded a GAAP net loss attributable to our class C class a common stock of 3.6 million.
Adjusted EBITDAX totaled approximately 133 million a 22% decline from Q2, resulting primarily from lower realized prices and higher elouise.
Turning to capital spending on slide eight in early September we reduced our rig count to five from six since we have confidence in achieving our planned activity levels with fewer rigs given the accelerating efficiencies we're seeing in the field.
For the quarter, we spud 21, and completed 17 gross wells compared to 20 320, respectively. During the prior quarter.
DNC Capex was approximately 160 million in Q3, and 11% decrease from Q2, notably this marks the fourth consecutive quarter of declining DNC capital as operating efficiencies and cost deflation are translating into lower well costs.
Facilities and infrastructure capital totaled approximately 40 million, which was down 9% from Q2.
Since centennial's formation, we've invested a significant amount of capital in infrastructure assets to ensure we have the flexibility to efficiently develop our acreage position.
Given the scale of our operated salt water disposal system in Reeves County, which is detailed on slide 10, we're exploring a potential monetization, which if consummated would provide significant capital resources that can be utilized for debt repayment or various investment opportunities.
The monetization of these assets will also eliminate the capital requirements of expanding and maintaining the system going forward.
Moving on to land capital, we incurred roughly 11 million Atlanta capital during the third quarter, which brings us to accumulative total of 35 million year to date.
As a result, we plan to pare back our land spend during Q4 to stay close to the 40 million high end of our original guidance.
Overall centennial incurred approximately $212 million total capital expenditures during the third quarter compared to 237 million in Q2. This represents a slightly greater than 10% decline quarter to quarter.
On slide 12, we summarize our capital structure and liquidity position last week or $1.2 billion borrowing base was reaffirmed by our bank group with 120 million of Outstandings at September Thirtyth borrowing base utilization stood at a relatively light 10%.
We maintained 800 million of elected commitments and had approximately 690 million of total liquidity.
Centennial's net debt to book capitalization at September Thirtyth was 24% and that up to LTM EBITDAX was 1.7 times with that I'll turn the call over to Sean Smith to review operations.
Thank you George.
This was another quarter of strong execution for centennial characterized by solid well results with a keen focus on operational efficiencies.
So far this year our operations team has done an outstanding job on both of these fronts before returned individual well results I'd like to take a moment to detail. Some of the operational improvements were seeing first hand in the field, which are shown on slide seven.
Beginning with drilling we've been able to reduce our third quarter spud to rig release by 26% to 23 days on average compared to last year.
This is primarily attributable to the ongoing collaboration between our drilling and geology teams importantly, we've been able to reduce drilling days without sacrificing lateral placement or well quality as we remained inside our approximately 30 foot target window, 98% during the quarter, including 17 wells, which remained in.
Zone for 100% of the lateral.
On the completion side, we continue to increase the number of stages stimulated per day compared to last year, we increased our average stages pumps per day during the quarter by roughly 30% to over six stages per day occasionally achieving nine stages per day.
The increase is driven by our employees on the ground driving efficiencies in the field.
Additionally, we benefited from overall service cost reductions specifically related to lower horsepower wireline and per ton profit costs.
Combined these efforts have resulted in reduced cycle times, and ultimately lower well costs overall, we've reduced our total cycle times, which we define as spud to first production by 17% versus last year.
This is translated into an approximate 22% reduction in total well cost for the quarter relative to our initial 2019 cost assumptions and the trend line indicates further reductions maybe possible.
As you can see from our capital numbers capital efficiency has been the primary focus in the second half of 2019, and we will continue to look for opportunities to lower cost as we head into 2020.
Now turning to results for the quarter Centennial ran six rigs for a majority of the third quarter before dropping to five rigs in September we were able to make this decision and still hit our production goals due to the operational efficiencies previously mentioned.
Turning to slide five in Reeves County, we brought online to co development test involving the third bone spring sand.
The Barracuda three well pad was drilled using approximately 10000 foot laterals in a stacked staggered pattern, combining one third bone springs, and well with two wolfcamp up raise.
The Wolfcamp a wells were spaced at 880 foot spacing, which is our normal spacing for this area.
Pad delivered an average IP 30 of approximately 1900 barrels oil equivalent per day and produced over 215000 barrels of oil during its first 60 days online.
The dock Hudson package also contained one third bone spring Sandwell paired with two wolfcamp up raise the 6000 foot lateral wells achieved an average IP 30 of almost 1600 barrels of oil equivalent per day or 216 barrels of oil per day per thousand foot lateral per well.
The Barracuda and dock Hudson's are important delineation test not only do they further validate the co development of the Wolfcamp Upper Ray and the third bone spring season, but these wells represent our southernmost test to date of the third bone spring sand on or Reeves County acreage effectively spent expanding our sweet spot farther south than original.
Anticipated.
Remember our initial development of this interval originated in late 2017 on the northern portion of our acreage near legacy third bone development in Southern Ward County.
Throughout 2018, we dialed in our efforts successfully pairing this zone with the Wolfcamp up Ray.
Earlier this year, we pushed the fairway west into our Miramar acreage with a strong fundamental and now we've delivered robust third bone spring sand delineation results on the southern portion of our Reeves County position.
These results continue to push the play southwards, providing us even greater confidence this high rate of return reservoir exists on the majority of our Texas acreage.
The third bone spring sand has now been developed into a top tier reservoir for centennial with essentially zero entry cost.
Turning to new Mexico Centennial completed the two well Acevedo state pad targeting the second bone spring with approximately 7000 foot laterals.
These wells delivered average IP thirtys of approximately 1300 barrels oil equivalent per day, 89% oil and continued to produce over 1000 barrels of oil per day 60 days after initial production.
We continue to be pleased with well performance on our new Mexico assets.
Now that we've established production from six different zones built infrastructure and put together contiguous land positions. This area is ready for additional development.
Yes, we shifted a second rig to new Mexico in August and recently transitioned from drilling one off wells with single mile laterals to longer multiwell packages across multiple horizons using longer laterals.
I point, you to the bottom right hand side of slide six.
You can see our average lateral length year to date into Mexico has increased 41% versus 2018, why our total cycle times per thousand foot of lateral had decreased 46% over that same period.
We also recently implemented a water recycling program and Lea County.
This not only lowers our overall completion cost, but also positively impacts Halloween.
Upon continued successful implementation into the northern Delaware, we'll look to apply a similar water recycling process in Texas potentially early next year combined these efforts should bode well for our 2020 capital efficiency.
Before I turn it over to Mark I wanted to touch on our exposure to federal leasehold as I know this has been a topic laid.
Out of our roughly 80000 net acre position spanning both northern and southern Delaware basins Centennial has only 4000 net acres or approximately 5% located on federal lands, all and Lea County, New Mexico, So with that I'll turn the call back over to Mark.
Thanks, Sean.
Now I'll provide a few thoughts regarding the oil macro picture and relate into Centennial strategy.
At a September Investor Conference I predicted that 2020 total you this year over year oil growth would be 700000 barrels per day, which at that time was considerably below consensus.
Given additional data are now think that 2020 year over year oil growth will be roughly 400000 barrels per day, which is below current consensus.
For the EPA nine Fourteens US production has been essentially flat for nine out of the past 10 consecutive months.
And it's likely to slightly decline over the next six months.
Most people will describe the low you this growth to capital discipline, but I think that larger reason is what I've been talking about for several years the shift to tier two and three drilling locations in all shale plays and increasing parent child issues in the Permian.
Ill also note that this is likely not just to 2020 of them.
I believe you this shale production on a year over year gross basis will be considerably less powerful in 2021 in later years than most people currently expect I leave it to others to opine on what this means for global oil markets.
Turning to Centennial.
Our aim continues to be a company that will be capable of delivering oil growth, while maintaining a prudent balance sheet in the future domestic industry that we believe will be growth challenged.
This quarter was another one the typified ceded.
Again raised our full year volume target, while maintaining our original Capex budget and overall unit costs are lower than our original guidance.
For me the most noteworthy item this quarter was a significant improvement in our DNC costs relative to early 2019.
This is occurring on both the drilling and completion side and bodes well for a 2020 capital efficiency.
In my mind Theres never been a question regarding our will quality.
From inception, we've always been the upper half ranking in the basin.
For those fixated on cash flow allow spend we're investigating monetizing areas WD assets.
This combined with lower well costs should ameliorate any balance sheet concerns.
Ensuring strong debt metrics and liquidity for both 2020 and 2021.
So I'll leave you with the final fun.
This year, we raised up production guidance twice without increasing capex, which implies that seed is growth versus capital situation.
Is more robust than many might have forecasted and highlights the quality of our acreage position.
Thanks for listening and now we'll go to Q than a.
Thank you question and answer session will be conducted electronically.
He would like to ask a question. Please do so by pressing Star then the number one on your telephone keypad.
Questions are limited to one question and one follow up question.
If you would like to withdraw your question press the pound key.
Your first question comes from Scott Hanold from RBC capital markets.
Thanks, Good morning.
On.
The.
I guess opportunities you monetize this the salt water disposal system can you give us a little bit of context of what you all have invested today down that and I think you mentioned that you potentially looking at building it out a little bit more to on some of the recycling and Texas would that would the recycling and disposal that all be.
Put together a package together as one or what did the size and plans for that.
George Your Sean you want to feel that.
So on the how much we've invested in this system, obviously I think thats, we can't really talking about that as we're just starting the process to pull the information together and working with.
Various banks to select who might be in marketing for that so can't really give out those costs right now as we're just starting that bidding out process and hope to have that wrapped up by Q1 of next year for the recycling.
Side of that question, we're excited about what's going on into Mexico from a recycling position and think that theres, some real opportunity to cut costs, both on the capital and the other OE side and as I mentioned in my part of the speech, we will be doing it in Texas late this year early next year, probably a little more likely we will couple that with this.
Salt water disposal divestiture somehow in the fact that we will need some kind of agreement with the purchasing company that we can do some recycling in there so plan to still recycle even if we look to monetize as system.
Okay, great understood and Mark maybe.
A big picture, obviously, it sounds like you're constructive on the all macro in a units in the next few years you guys are down to five rigs, but I've seen some efficiencies I mean, if you could you give us some context I know, it's probably too early for 2020 budget, but some context on how you think about activity and outs.
And in kind of that view.
Yeah.
Just some general context get the number one the 30% debt to cap is still a.
Pardon the guideline for us thats kind of the.
The primary guideline. So we are not flexing on that.
In terms of what we do.
I'm not going to provide any any guidance as to what we're looking at for production target in 2020 at this time, but.
But the primary guideline will be we're not going exceeded 30% that cap number.
What I will say is that the.
We've never mentioned the disposal of the SWT assets up to this point although.
No other companies that.
Have looked at it done that.
Prior times.
If you look back at the background of one I was running yield G.
We never monetized any of.
You know.
Assets in house any of our processing assets or or anything like that we never went for.
Any of those those particular.
Monetizations in the MLP is there anything and so we followed the same philosophy here I've always up up to this point really believes that the.
There is a better valuation keeping those in house, but.
Times have changed here and not clearly, there's there's an investor fixation with cash flow outspend. So.
So looking at this potential.
Cash flow outstanding the we're faced with possibly in 2020.
We are saying well one way to solve that problem is too low to monetize this w. dee.
And in fact it would.
Essentially sold.
For multiple years down the road. So if we did that it would give us a lot of flexibility as to what we do in terms of Capex for 2020 and.
Potentially could allow us to have a from a growth mode on the production side. So so any early stages of looking at monetization.
But it gives us additional flexibility and I think up to this point.
People have you'd see Dev in 2020 is.
Well, we're either going to have to bus that 30% debt to cap in a $55 oil world or we're going to has to show a zero gross or a very very small production growth.
And that's been a parent lead pretty on appealing to the average investor and.
This is another weapon that we have.
That can still allow us to stay within 30% debt to cap and ER and give us a lot more flexibility as to what we do.
Next year, and if you combine that with the macro that I believe we're going to have very small.
Year over year total you this production growth.
Which may affect the global oil price I won't predict that one way or another.
In the it gives us I think of potentially a good set up and I think should allow investors to view this in a.
A more constructive light for both 2020 and 2021.
Got the that's good context. Thank you.
Thanks.
Your next question comes from Neal Dingmann from Suntrust.
Thanks for details Mark Mark when it's pushed pretty I guess for you were Sean.
You've done a great job, particularly here in the last quarter to on bringing well costs down I guess, a pretty broad question. When you see I guess just the Mt of room, you see that for when you look at 2020 for additional well cost improvement.
Both just on the operating the side and then all the way I guess, including Halloween and everything else all the way to the production side.
Yes, let me address on a capital side, and then I'll ask John to them to address it on the Opex side.
Probably one of the most pleasant things we've seen throughout this year.
This is a significant decrease on basically well cost side.
DNC said most of the wells, we drilled an hour or 7500 foot laterals at that seems to fit in our acreage best So just relating to 7500 foot laterals and that's why we said the.
The costs.
Currently are down 22% from from our initial 2019 estimate.
But I would say.
There is room for those costs to go down further than than 22% and <unk>.
A recent trending wells indicated.
The trend continues at the 22% is not the maximum.
Delta that we want to see.
It's occurring primarily on the completion side, but also clearly on the drilling side too.
The biggest portion of that is coming through in the completion side.
And.
Let's say, if we stay in a $55 oil environment for 420 20.
The likelihood is we will see further reductions.
Over and above the 22% that appears to be the trend.
We're on and again.
When you view when see Dave is viewed as a company that.
You know.
Earlier in the year.
Reviewed as a company that my gosh for the capital we're spending a theres no way that they we could have any growth.
Stay within certain financial limits, I think that needs to be revaluated based on the results that were putting up on the board versus capital.
So that's the trends that we're seeing in the capital side and I think.
Other Permian operators are reporting similar trends so it's not that were an outlier.
On the Opex side, let me have Sean address that the particularly some of the things on the other Lee side, which I know is a key question.
Yeah markets George I'll go and take that as you saw we did see some increases in our.
Although we expense, which we revised in our guidance estimates for the year. Some of those are in the one off category.
In terms of electricity costs, which had a spike in August given some extreme summer heat, where we saw rates spike over a period of days.
And beyond that we have some increases in terms of chemical costs in rental.
Equipment rental rates and so we've already put in place a series of actions to help mitigate that.
One of those involves building a.
Power substation in Reeves County, that's a project that we've done some spending on in this year and some spending on next year it'll be operational mid year.
And what that will do for us it will reduce our reliance on generators for our SP.
Our pumps and thereby increase our efficiencies increased reliability and reduce downtime on the chemicals front. We've also swapped out vendors there in an effort to be more efficient around our treatments and our costs on that so we are addressing these kind of one by one in an effort to.
To mitigate the cost increases we saw in Q3.
Great details guys and then just.
One last follow up just nobody likes to have then I guess, the most linear type production growth from just one with the five rigs running next year, how should we think about that on a quarterly basis versus having the larger pads and maybe blocking up some some completions et cetera.
In terms of what our production growth might lead with five raises that your question Neil.
I mean, I'm just wondering more on everybody loves the habit is smooth as possible you know everywhere, we kind of grow equally each quarter I'm just wondering mark when you look at it is that possible I guess I'm asking given.
The need for the the efficiencies with the larger pads.
Yeah, well I guess for first part of that is we haven't really decided whether we're going to run five and exactly how many rigs we're going to run next year.
So we're not committing five rig rig contracts give us a lot of flexibility so.
We'll we'll give you some context on that into February call as to how many rigs we plan to run specifically.
In terms of the number of.
You know wells per pad or whatever that we plan to run we're still going to stick with with the.
Not going to.
The giant Q type drilling sequences or anything like that.
Generally com four wells per pad three wells per pad that that seems to work best for our acreage configuration and so.
There won't be huge amounts of lumpiness.
That you'll see in terms of quarter to quarter production performance.
You know that would be more typical you know some of these things like dominator pads or some of those kind of thing so I would say.
A small amount of lumpiness quarter to quarter, but less than you might see from somebody other companies that are going to.
The Q that large Keith.
Patterns, so very good. Thanks, thanks, So mark Mike Okay.
Your next question comes from Subash Chandra from Guggenheim Partners.
Yes.
Good morning, guys I, just want to ask for water questions, but that differently.
At the current utilization.
Of those a water assets.
Do you have a number.
What's your parents salt water disposal volumes are.
Georgia, Sean you want to fast Dubai cash this is Sean.
I hate to to keep using this kind of excuse but we've just gotten into the process here in so I really don't want to give out too much information until we.
I have.
Our bank onboard and potential suitors had the information in hand, I will say that we are currently producing over 200000 barrels of water per day as a company our infrastructure system in Texas has permitted capacity.
In the ground 200.
I think it's 280 260000 barrels of capacity in the ground with permits for another 120000 barrels so.
Those are the kind of numbers I guess I feel comfortable giving out right now.
Okay, Yes, no gotcha.
And then could you share this number I guess of the.
The facilities expense in 2019, I think the you know a budget range or 121 60, how much of that was for the water.
Yeah, we haven't disclosed that see Bosh guide you to is if you look at our 2018 spend in the disclosure in our 10-K.
If you aggregate the facilities and infrastructure spend about 75% of that was facilities related and 25% was infrastructure related.
So that that should give you a sense of the.
The split.
Between those two buckets of capital when I think for this year.
No.
Not exact to that number, but I think directionally will be similar.
And this would count as facilities or.
This would be a horse SWT structure spending yep yep, Okay got you.
And just one for the presentation I think on slide.
Six just wanted to make sure I'm interpreting this correctly in the Lea County.
Cycle times, I think the far right the lower box graph on.
Slide six in the far right.
Craft, there 7.9 dose of 4.3 per thousand feet is days per thousand feet.
Yes, it is and so a way to think about that it's kind of an interesting metric, but it's really trying to normalize for lateral length right. So if you want to say, it's at a 10000 foot well just using it as an example would have taken 79 days from spud to initial production in 2018, whereas that same 10.
Thousand foot well would take 43 days.
You are today 2019.
Got you from spud to sales, yeah, but seems really really fast so one too.
Make sure that thank you you that thank you bye.
Your next question comes from Charles Meade from Johnson Rice.
Good morning, Mark to you in the whole team there.
If I I appreciate the comments you gave us some some coordinates for how you're thinking about 20, but I wondered if I could just perhaps could you elaborate not so much on on our numbers, but priorities for 20 I get that Youre. Your hard metric is that 30% debt to cap, but but what would what would come in after that.
That would it be is it a priority to keep production flat if possible.
You are in and what's the what's the timeline.
If you have any time to meet what's your what's you called it you know this this obsession around this fixture on on free cash.
Yeah.
The overall underwriting.
Comment I guess, the overriding strategy for C. diff those goes back to the macro.
So just to just to said it in it.
From 30000 feet.
I believe the U.S. is going to be in a.
Gross challenged environment.
Period 2020 through let's just say 2030.
In other words that production growth is going just.
Year over year U.S. production growth is going to be considerably less than most people are currently forecasting.
So they're going to be disappointments across the board with individual companies production growth and I think you're going to see that starting in February when you see what each company is actually forecasting for production growth next year and that's going to continue in 21 234 or five so on.
And so.
As that happens.
I think investors are going to seek out companies.
That actually can achieve year over year production growth and that's going to.
Be a function of whats the relative quality of the prospect inventories of each company and.
Our goal is to have a good prospect inventory, hence the slide weve shown on our expanding bums brings a third bone spring.
Prospect inventory as one example in the attachment this.
This quarter.
And so.
Wheat, and and one would assume if U.S. year over year gross is sluggish.
That at some point.
Global oil prices will increase now I'm, not saying that's going to happen in 2020, I don't know when it's going to happen, but we want to see to add to be in position.
To be able to grow at that time now.
If 2020 is not when global oil prices increase then you know, we will probably respond accordingly, and and not strive to have a significant production growth.
And and we will gauge our capital program Accordingly.
But when.
Global oil prices become more robust.
We will then adjust our capital program to a to show production growth and that will likely be in a world where other companies will be growth challenged.
And there will be growth challenged mainly because of the.
Shale plays or.
Going to not be as prolific is as people are currently alleging that they are.
So that's that's a general point and and we're not going to allow this company to be heavily indebted.
As such that whenever the the oil market improves that that we're going to be burdened with so much debt that we won't be able to grow because of debt constraints. So hence.
30% is kind of a magic number that this is the you know we don't want to go over that amount.
Uh huh.
That's what I would say is kind of a red line on the debt. So we're going to manage the company.
If oil prices stay at 55 or stay low to not to not go over that Red line until we see oil prices improve.
So hopefully that gives you a little bit of underlying philosophy of the company.
Mark that's that's actually really informative for me. So I. Appreciate you are you taking the time to answer that way. It also.
It's up to the second question that I had which is up about the third bone Springs, there I should move south in Reeves County in my understanding.
You've always known that zone is there a there's just the question was whether its perspective or not and now the with these road weve with these well results you've shown this perspective and so I'm curious does that change your view about how far south you might be able to push the bone springs or Alternatively does it does it change your view about maybe as you go up in the column.
To the said you have second after first bone springs and in that same posters ship.
Yeah. It the the answer short answer is yes chose it.
It.
It changes our view and makes us more optimistic that that the third bone spring sand can be pushed farther to the south on our acreage I mean, if you look at the.
Slide six or whatever it is slide five there.
It it certainly makes.
Makes us more confident that that Orange E lips.
As time moves on can be further push to the south now that.
The ROP changes in terms of it what it looks like Stratigraphically as you move to the south.
But the.
But it's our hope and I believe that.
We think we can expand that the and hopefully maybe across all of our acreage so to the south and to the west as you've seen so hopefully you know within six months, maybe that orangeade lips kinda covers all of our yellow acreage there.
And it also gives us a little more confidence that farther up into section that the in the second bone spring that the that maybe there is a zone. There that we can test we've kinda suspended testing farther up in his section.
As oil prices has not been conducive to.
To to doing a whole lot of additional testing in a section, but and again, we know right now that the.
In our stock valuation, we're not getting paid for expanding prospect inventory on our acreage in fact, I think people probably say.
Yeah, hi, or even spending precious capital on doing is but I belief is that that's a very wise investment and at some point that it's going to.
Be worth its weight gold, particularly on our existing acreage.
Thank you for the commentary Mark.
Okay.
Your next question comes from is it safe from Bank of America Merrill Lynch.
Thanks, Good morning up two quick follow ups.
Thanks for the color on on well cost and a very impressive reduction just wondering.
What the leading edge or average will cause average if you could share with us DNC per foot.
Either in southern Delaware or new Mexico.
I think Mark mentioned 7500 foot lateral as an average.
Yes it.
We really don't want to give give out it that's kinda like what's sort of intrinsic decline rate of a production base a.
Feeling is if we give a dollars per thousand feet or something like in our well cost. All that does is whoever comes behind us on the earnings call Tomorrow with the following day, we'll just say, we'll we'll we'll match that number and top it to show that we can be whatever ceded has come out with so we just prefer to say.
Hey.
We think it's very competitive with the you know what what other people are doing whether it's the absolute best in it you know.
Peer group, we're not sure because it's moving target.
So we just kind of leave it that.
A significant improvement, it's showing up in our capital numbers clearly.
And it probably got room to them.
To improve further as we go into the fourth quarter in Twentys wanting.
Okay, and then just wondering the wells that you highlighted this quarter.
Had relatively high oil cuts.
Should we expect going forward again this is few wells, but oil cut.
Moving.
Slightly higher or should we expect the consistent oil cut range that you experienced so far.
Yes, Good question, Georgia, Sean you want to explain the oil cut situation trial. This is Sean.
So for the third quarter was a little bit lower and oil cut yes, we had some production. Some wells we brought on line and Miramar, which is a higher JLR area, which brought that a percent oil down a little bit for three Q4 quarter. We'll go back to closer to what it had been in prior quarters and we still hold from our our average for the year I think is.
We have 57% for the year for oil cut so which would imply in Q4, it's going to be certainly higher than Q3.
Yes. It let me let me just give you little color on that just as we relate to Miramar. If you just look on it slide on page five just to give you a little color there.
You know Reeves County acreage.
The oil cut is remarkably consistent across all of our yellow acreage, except that acreage as shown in the northwest there northwest and that kind of like where that strong fundamental well as highlighted if you happen to be looking at that particular slide on slide five that's called our Miramar area.
That is a higher deal or area clearly.
So.
And any time, we happened to drill in a quarter.
A higher kind of disproportionate number of wells into Miramar area are a deal or the next quarter is going to pop up.
And so it's a function of how many wells that we brought online in a miramar area relative to everything else.
On there so.
It moves a little bit because that is one area, where we have a disproportionately high gas ratio relative to everything else and in new Mexico.
There we have a relatively low gas ratio. So if we bring on a bunch of wells in new Mexico. It will bring the will cut up relative to.
Hopefully that just located pictorially, a little better for you.
So I appreciate the color Mark Thank you.
Your next question comes from Kashy Harrison from Simmons energy.
Hi, Good morning, everyone and thank you for taking my questions.
So first off a quick follow up to an earlier question I think you were talking about some of the spend from.
29 team that there was a 75% bucket those associated with facility than 25% associated with infrastructure at those the right way to think about it entering 2020 that that that piece that you consider facilities spend would be highly correlated with.
The change in DMC year on year, and then we would expect the infrastructure spend to be lower next year due to the monetization of the world or potential monetization of water assets.
Yeah Cashew. This is George the 70 525 split was.
Tied directly to the 2018 spend although directionally, that's split will be similar but.
Yes, I think the way we think about it on facilities is.
As we move forward in terms of developing the field further.
I think that utilizing centralize tank batteries and things like that and coming into existing pads will probably scaled down that spend relative to our DNC capital over time.
Infrastructure is clearly a more lumpy category and.
A monetization of the us Wses SWT system would certainly.
Reduce that on a go forward basis very very significantly.
The power substation is something that that as a.
Capital item, that's kind of split between this year and next but but that infrastructure bucket would go down very significantly going forward.
So it sounds like non being few spend would be.
Or could be materially lower next year about yes.
And then.
Mark I know you're reluctant to provide lateral adjusted well costs. So I was wondering if maybe we could just use a bigger number or are different metric. So to speak on can you just give a sense of just capex per rig per year, just for us trying to as we try to calibrate some capital official.
See numbers entering 2020.
Well.
Yeah, I don't I don't know, Sean do even lean and look at things in that manner.
We havent a I mean, obviously, we have the numbers, but we haven't disclosed that type of number.
Yeah, I think we'll pass on that one can see.
[laughter] Ben I'll try one more so I know I know you're reluctant to provide underlying base decline, so I'm not going to ask for the exact number but.
Since since the rate of growth is slowing I was wondering if you could just give us a sense of the rollout of the relative rate of change and entering 2020. So for example would you expect that base decline to be flat 2020 versus 2019, 5% lower 10% lower et cetera, just just some thoughts on the change would be helpful.
Yeah, It's I mean that it's going to be lower in 2020, probably to the tune of the three or 4% lower.
You know versus 29 team.
And.
And you know weve.
I think the one thing you can say is.
You know, where where they stopped blew up and everybody kind of debt disappointed was in February .
Where.
You know leads we said we're going to get off the production growth train and slowed on the capital program and everybody said Oh My Gosh, you must have a horrible decline rate because your production grows can be much less than we thought when you cut your capital.
But I just go back and say okay now.
Play that through the end of year and we've raised our production growth twice for the same capital amount.
So something has happened this year, either we're drilling better wells or our decline rate was not as onerous as everybody thought in February when they ran away from the stock so.
I would just say that.
The situation.
Within C. diff is not nearly as dire.
In terms of decline versus capital as.
People assumed in the first quarter.
On our February earnings call, which everybody.
Declare the disastrous earnings call.
So.
Overall this company is in solid shape, we have relatively low debt, 24% debt to cap.
We just consistently hit it out of the park on our wells and you know are operating costs are in pretty decent shape.
And.
Our plays continue to expand and third bone spring so.
Overall. This this is a pretty good company really Ana.
If we look at monetizing the salt water disposal system.
Suddenly for the next couple of years.
You know a problem on this cash flow outspend just goes away.
So.
I'm not that concerned I'm certainly not in any panic mode in terms of looking at this company.
That's helpful. Thank you.
Your next question comes from Derrick Whitfield from Stifel.
Good morning, all.
Hey, David.
For my first question I'd like to approach to last few questions from a slightly different perspective.
Perhaps for Mark in light of your improved operational efficiency metrics and capital efficiency comment would it be reasonable to seem you could hold 2020 production flat with 20% less capital.
Seemingly of capital costs and based upon factors as Tailwinds.
Wow.
Yes.
I guess the way it answer that you know that given a percent is that.
It will be reasonable to say, we can hold 2020 production flat with less capital than.
Than everybody, including Wall Street would've expected, just six months ago, but whether the numbers, 20% less or not.
I don't know.
In fact, I haven't even calculated Derek so it can't give you a quantification, but clearly with less capital than we thought.
You know the 22% less well cost.
Would imply you know I guess you get back into some number in that range on their on there, but don't hold me to 20%, but clearly less capital.
That's for sure.
And Mark that was the basis to is really just on the 22% capital efficiency improvement and just seems like Theres a lot of Tailwinds supporting your business right now that aren't showing up on your stock.
Yeah, I would I would agree with that there [laughter].
And then as my follow up I'll, probably direct as you as well Mark.
While Centennial clearly has limited federal exposure could you share with us your broad views on the likelihood that a frac band could be affected by the executive branch of the government.
On federal acreage and secondarily, what you could do to mitigate your exposure on the 5% of your acreage that is on federal lands.
Yeah.
I.
And again. This this is without having a vast amount of expertise I'll caveat with that.
Yeah, you if he did get some Democratic administration in there and they did impose a.
Quote unquote Frac ban on federal lands I think that would immediately go to the to the courts and.
I think that you know you would have a protracted.
Time in the courts, there and it'd be pretty.
My guess is that would that would take legislation.
So you'd have to have both houses of Congress. It would pass AD. So you'd have to assume that Democrats would take over the Senate to.
I think it would be a long drawn out fight in many many years before that would that would actually occur.
In terms of mitigation.
So you'd be looking at probably 345 years down the road before such a ban would actually get enacted if if ever if at all.
I mean for Cts case, since we only have 5% or acreage there.
We.
We could fairly readily shift away from that 5% acreage.
You know it would only have a minor effect on on our specific situation.
So that that would be just my often.
Ideas there I suspect that would you know the whole thing about a federal ban on tracking on federal lands with.
Would probably be one of this campaign promises it would never never actually get enacted that's my belief.
Thanks markets are helpful in both topics.
Your next question comes from will Thompson from Barclays.
Hey, good morning.
Markers, Sean can you give us a sense of the contribution from GNC efficiencies and cost deflation in the 22% lower well costs you mentioned go into larger pads in the north Delaware.
Just curious on where you are in terms of maybe zipper, fracs and simops driving down DNC cost.
Yes, Sean do it.
Yeah, Thanks for pointing that out I think what you'll see on in the slide deck on page seven really talks about our overall company efficiencies that we enacted and what you'll see there's a longer laterals.
Our percentage of multi well pads being utilized across the board, but Texas into Mexico, and then on top of that the drilling and completion efficiencies. So to your specifically to your examples we are already doing zipper fracs and things like that so I think were on top of that from that perspective, but certainly increasing them or wells per pad to a point.
We will continue to drive efficiencies as well so I think as Mark stated earlier, we've got an opportunity to reduce costs further even if service costs remain the same we continue to get better ourselves as well as the industry on both ends of that both drilling and completions and to look forward to seeing a further reduction in.
Into next year.
That's helpful. And then just I just want to reconcile the 22% lower well cost versus expectations for Capex, <expletive> kind of trend towards the higher end of the Capex range I recognize that you're trending to the high end of the gross till cranes, which is now the midpoint of the revised till guidance, but.
You would think the lower well cost would offset somewhat so I'm just trying to figure out if I'm missing something.
Yes, yes, one point there will yeah that.
I mean, we're just now seeing these lower well costs. So.
We went through the first half of the year.
With without seeing these these 22% lower well costs and really we went through a fair amount of the third quarter without seeing these lower well costs. So we're.
We're going to see him into fourth quarter, and really some part of the third quarter, but.
That's one of the reasons why we're not seeing.
No.
A massive deduction in the Capex for 2019.
There so.
I think thats, probably the biggest explanation.
No that makes sense I guess I misinterpreted the 22% being for the FLIR, Okay that makes it. Thank you.
Okay.
And we have reached the end of our allotted time I will now hand, the call back over to Mark Papa for closing remarks.
Okay. They just close by saying, there's there's four important points I'd like to everyone take away from a this this earnings call.
First point is that the we're clearly seeing capital costs come down dramatically as we've talked about on this call and it looks like the capital costs still have room to run two would come down as more second point is that.
We have raised production guidance twice last two quarters.
With no increase in our Capex budget.
So there must be something going on within the bounds of C. diff. This very positive to look to see that occur.
Either in our intrinsic decline rate or in the quality of a room or wells that we're bringing online third thing.
Is.
The third bone spring sand continues to expand on our acreage through a step out drilling in the and even though.
People aren't giving us any value for that right now that does increase the intrinsic value their acreage and clearly gives us better well inventory quality and the fourth thing is the.
Potential for SWT monetization, which.
I think everyone would agree will give us additional flexibility in our capital program as we go forward.
If indeed this monetization.
The does come to fruition. So thank you very much for for your attention and we'll talk to you next quarter.
This concludes todays conference call you may now disconnect.
Yeah.
[noise] Oh.