Q2 2019 Earnings Call
This conference call.
To discuss its second quarter 2019 earnings.
Today's call is being recorded a replay of the call will be accessible until August 22019.
By dialing 8558 Fivenine.
Two zero pricing and entering the conference I'd number 18579 cemetery.
Or by visiting Centennial's website at Www <unk>.
C D E V I N C dot com.
At this time I will now turn the call over to Mr. Hayes maybe.
Continuous director of Investor Relations for some opening remarks. Please go ahead.
Thanks in rent.
And thank you all for joining us on the company's second quarter 2019 earnings growth.
Presenting on the call today are mark tapping, our chairman and Chief Executive Officer.
George Lucas.
Our Chief Financial Officer.
And Sean Smith, our Chief operating officer.
Yesterday August 5th.
We've got a form 8-K with an earnings release reporting quarterly earnings results for the company and operate and operational results for our subsidiary.
Centennial resource production LLC.
We also posted an earnings presentation to our website that we will reference during today's call.
You can find the presentation on our website home page or under presentations at Www Dot C. diff Inc. Dot com.
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 are beyond our control and are discussed in more detail in the risk factors and forward looking statement section of our filings with the SEC.
Including our annual report on Form 10-K .
For the year ended December 30, Onest 2018.
Although we believe the expectations expressed are based on reasonable assumptions they are not guarantees of future performance.
Actual results or developments may differ materially.
We may also refer to non-GAAP financial measures to help facilitate comparisons across periods and with their peers.
For any non-GAAP measures, we use a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website.
With that I will turn the call over to Marc Pappas, Chairman and CEO .
Thanks, Amy good morning, and welcome to Centennial second quarter earnings call.
Our presentation sequence on this call will be as follows.
George will first discuss our quarterly financial results updated guidance and liquidity.
Sean will then provide an operational update including recent efficiencies and lower yields.
And then I'll follow with my macro view and our current strategy emanating from the macro.
Now I'll ask George to review our financial results.
Thank you Mark as you can reference on slide 14 of the earnings presentation net oil production for the second quarter averaged 43100 barrels per day.
Which delivered 6% sequential production growth from Q1, and 38% growth over the prior year period.
Strong production results were driven by excellent well performance and a higher pace of completions generated by improved drilling and completion efficiencies.
Average net oil equivalent production totaled approximately 76125 barrels per day also up approximately 6% over the prior quarter and up 32% over the prior year period.
Oil volumes represented 57% of total production for the quarter.
With our six rig program, we spud 23 gross wells in Q2, which was up which was six more than the prior quarter and completed 20 gross wells, which was equal to Q1.
As a result of reduced cycle times, our year to date pace of activity has exceeded our original expectations.
Therefore, we plan to drop a rig in early September and will run five rigs for the balance of the year.
Additionally, we anticipate that the number of spuds and completions for the year will be at the higher end of guidance, even with operating one fewer rig from September onwards.
The combination of operational efficiencies and strong well performance is allowing us to increase our production guidance for the year, while maintaining our current capex range with that said, it's reasonable to assume that will be in the upper half of our capital range given that the improvement in cycle times have increased the expected number of spuds and completions for the year.
Revenues for the second quarter totaled approximately 214 million, which was a 14% increase over Q1, primarily because of higher oil production and realizations.
Oil realizations before hedging were $54.63 per barrel compared to 40 815 in Q1.
Inclusive of the modest impact of our basis hedges centennial's realized oil price for the quarter was $54.45 per barrel offsetting the rebound in oil realizations were pricing declines for both Ngls and natural gas our realized natural gas price before hedging was 81 cents per Mcf and NGL realizations were 16 24 per barrel.
Shifting to expenses cash DNA per barrel was down approximately 6% to $1.78 as notional gionee increased marginally compared to Q1.
Hello, we per barrel increased 9% quarter to quarter, primarily as a result of higher equipment rental rates chemical costs, and thus WD costs.
GP and T. expense per barrel was essentially flat at 234.
DDNA expense increased by nearly 9% from Q1 to $16, an 18 cents per BOE, which was still below our midpoint of guidance.
Finally, severance and AD valorem taxes were 7% of revenue compared to 7.5% in Q1.
Adjusted EBITDAX totaled approximately 170 million for Q2 at 21% rebound for Q1 and GAAP net income attributable to our class a common stock was $17.9 million.
Turning to capital spending DNC Capex was approximately a $180 million in Q2, a 5% decrease from Q1 to spyros, despite higher activity levels, particularly on the drilling side.
Notably this marks the third consecutive quarter of declining DNC capital as our drilling and completion efficiencies are translating into lower well costs.
Further reductions in per well costs are a significant point of focus for the team.
Facilities infrastructure and other capital totaled $44.6 million, which was down approximately 2% from Q1.
More specifically facility spending declined by approximately 30% while infrastructure spending increased significantly as we invested in a water pipeline to expand our Reeves County, salt water disposal system.
These are prudent dollars to spend because they provide a significant operating flexibility.
Maintain lower LNG over time and are very valuable assets in todays market.
Finally, we incurred roughly 13 million in land related capex during the quarter as we continue to capitalize on attractive opportunities to add high quality acreage at compelling valuations around our existing positions in both Lee and Reeves counties.
Overall centennial incurred approximately $237 million of total capital expenditures during the quarter compared to $245 million in Q1.
Given our year to date results, we are increasing our daily oil production midpoint guidance by 5% to 41000 barrels per day.
While maintaining our capital guidance range for the year.
Additionally, we are reducing the midpoint of our cash SGN, a guidance by 16% to $2.10 per Boe.
And GP and T. guidance by 12% to $2.65 per Boe.
Finally, we are reducing DDNA per barrel to a midpoint of 16 25 from 16 50.
On slide 12, we summarize our capital structure and liquidity position at June Thirtyth, we had approximately $28 million of cash.
Zero borrowings under the revolving credit facility and $900 million of senior unsecured notes.
Based upon the $800 million elected commitment under our $1.2 billion borrowing base credit facility. The company had approximately $830 million of liquidity at June Thirtyth.
Finally, our leverage profile was essentially flat quarter to quarter.
Centennial's net debt to book capitalization at June Thirtyth was 21% up modestly from 20% at March 30 Onest.
Net debt to last 12 months EBITDAX of 1.3 times with.
And just from the prior quarter.
With that I'll turn the call over to Shawn Smith to review operations.
Thank you George.
The second quarter represented another quarter of solid execution for centennial driven by higher than expected well results and continued efficiency gains, which translated into a higher pace of activity.
Year to date, our operations team has done a tremendous job reducing cycle times for both drilling and completion activity.
Beginning with drilling on slide seven we've reduced our average spud to rig release by 15% year over year to approximately 27 days during the first half of 2019.
We've seen a reduction in drilling days and both our Texas and new Mexico assets, which is primarily attributable to the ongoing integration of our geologic and drilling databases.
Additionally, we have made achievements in our mud systems and down hole assemblies designed to perform optimally based on our evolved understanding of the reservoir characteristics.
Similarly, we are completing more stages per day compared to 2018 during the first half of the year, we averaged approximately six stages pumped per day or roughly 25% increase versus last year.
In addition to these efficiencies gained completion cost continue to trend down year over year.
As a result of both reduced horsepower cost and per ton proppant costs.
Combined these efforts have resulted in increased capital efficiency as year to date, while costs are approximately 5% lower compared to 2018.
Importantly, we expect this trend to continue throughout the remainder of 2019 as a result of continued improvements in operational efficiencies and service cost pressure.
As you can see on the right hand side of slide seven our operational cycle time improvements have allowed us to bring more wells online than we originally anticipated this year.
Therefore, we expect to reduce our operated rig count from six to five rigs in early September while spudding and completing more wells than previously anticipated under our original six rig program.
To put this into context during the first six months of last year, we spud and completed 41, and 36 wells, respectively, utilizing a seven rig program.
This year, our six rig programs, but essentially the same amount of wells and we've completed an additional four wells compared to the first half of 2018 put simply we are doing more with less and as a result, we are ahead of plan for the first half of this year.
Just as important we've been able to drive well cost and cycle times lower without sacrificing well quality as you can see on slide four we've built upon the productivity gains we saw early in the year. This graph depicts centennial is 2019 year to date wells completed versus our 2018 vintage wells and includes all intervals.
The main point here is that we've increased well productivity year over year as our 2019 wells are outpacing 2018 results.
Now turning to second quarter, well results on slide five in new Mexico Centennial completed its two best producing wells to date.
The first well the trees of six or one age targeted the third bone spring with an approximate 9800 foot lateral.
With a 24 IP, but the 24 hour IP rate over 4000 barrels of oil per day. This well achieved an IP 30 of over 2500 barrels of oil per day or 260 barrels of oil per day per thousand foot of lateral.
During its first 60 days online the trees are produced over 110000 barrels of oil and represents our best wells drilled to date.
On slide six the three well Duck Hunt pad also located in new Mexico was drilled with approximately 90 or 6900 foot laterals targeting the first second and third bone spring intervals.
These wells were directly stacked with approximately 800 feet vertical separation between intervals and completed simultaneously for reduced cost and higher efficiency.
These wells delivered an average IP 30 of approximately 1800 barrels of oil per day or 266 barrels of oil per thousand foot of lateral and included the second best well ever drilled by Centennial.
As evidenced by recent results, we continue to be extremely pleased with our northern Delaware position, which we initially established in mid 2017.
Since then we've continuously operated one rig on the acreage and essentially all of our results to date have either met or exceeded expectations.
Given these results we expect to ship one of our Texas rigs to New Mexico later this month.
At that time Centennial will operate two rigs in Lee County, with the remaining rigs located in Reeves County.
Remaining on slide six and Reeves County, the Red rocks, four well pad was drilled using a stack staggered pattern targeting the third bone spring sand and Wolfcamp upper eight intervals with approximately 9500 foot laterals.
These wells were spaced approximately 880 to 1000 feet apart, which is our normal spacing pattern in these intervals.
The two third bone spring wells delivered an average IP 30 of almost 1900 barrels of oil per day or 182 barrels of oil per day per thousand foot of lateral.
The two wolfcamp upper a wells delivered an average IP 30 of approximately 1800 barrels of oil per day or 201 barrels of oil per day per thousand foot of lateral.
The Red rocks is an important test first it represents our first four well test pairing the wolfcamp upper a and the third bone spring sand proving the viability of multi well co development.
Secondly, the production profiles for these wells confirms that the third bone spring sand will compete for capital with our best rate of return projects.
We plan to continue developing the third bone spring sand and where possible co developing this zone with the wolfcamp debris, thereby enhancing overall economics.
Before I pass it off to Mark I'd like to touch quickly on natural gas pricing within the basin as it has become quite topical as of late.
On last quarter's call, we predicted that natural gas prices at Wahoo.
We continue to trade at or below $0 for the remainder of the second quarter.
In fact, wahab prices averaged negative seven cents during the quarter and as you can see in slide nine.
Fortunately for Centennial since April over 70% of our natural gas sales volumes have received mid con pricing based pricing as a result of our firm sales and firm transportation agreements.
This allowed us to realize a positive 81 cents per mcf on a weighted average basis during the quarter.
While natural gas takeaway from the Permian will improve later this year.
We would not be surprised to see the base and returned to being oversupplied and mid 2020, putting pressure once again on while higher prices.
This potential threat is one of the many reasons why our current gas takeaway agreements extend through Q4 2022.
This is key for two reasons number one it means centennial will continue to be an industry leader in terms of minimizing natural gas flaring.
Number two we will continue to enjoy price diversification through our ability to access delivery points outside of the Permian basin.
In closing Q2 represents a very strong operational quarter for Centennial, we brought online four of the top five wells and Centennial history and these wells are notable because they targeted three separate zones and we're equally split between Lee and Reeves counties.
As we highlighted on slide four the operations team and all of our employees at Centennial continued to deliver on the goals set forth at the beginning of the year from well productivity to capital efficiency to GE and eight per barrel Centennial continues to operate at a very high level.
With that I will turn the call back over to Mark.
Thanks, Sean.
Now I'll provide a few thoughts regarding the oil macro picture and relate to this and Teneo strategy.
The supply side of the global oil picture is bullish.
And it's already apparent to me that 2020 total you list a little growth will be considerably less and the 1.2 million barrels a day year over year that most people are currently forecasting.
The Big question is global demand and nobody including the currently has a clear picture of either 2019 or likely 2020 year over year demand growth.
I personally believe there is an equal probability that 2020 oil prices could be $50 or $70.
So where does that leave ceded strategy.
For the third consecutive year and mid year, we've raised our volume targets lowered several of our unit costs and expect to stay within our original Capex budget range, albeit on the high end this year.
That's a three year consistent track record few ERP NPS can claim.
Although we are outspending cash flow.
Our current debt to cap is only 21% level, most NPS would envy.
Also since this is a current hot topic, you should be aware that are Texas Permian basic well spacing has always been 880 feet, which is likely the most conservative in the industry.
Our wells on average continue to slightly outperform our model type curves, which is reflected in the current increased production guidance.
Overall I believe we are performing as an efficient well run Permian mid cap.
Thanks for listening and now we'll go to Q and aim.
Oh Lorenz.
On slide Cuban a force please.
Thank you.
The question and answer session will be conducted electronically. If you would like to ask a question. Please do so by pressing star good at 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 the line of.
Scott Hanold from RBC capital markets. Your line is open.
Thanks, Good morning.
Yeah, Mark I was you know I'm not play up that last comment you made about there is possibly an equal chance of oil being 50 or 70 next year.
As you step back and look at running five rigs it looks like for the course of the rest of this year. How do you plan then for 2020 and like what does the base plan at this point like how should we think about the.
Cadence of activity to expect from seed of going into next year.
Yeah, a good question Scott not.
Just going to have to give you that but rather nebulous answer.
Flexibility is going to be the watch word.
Uh huh.
The one advantage we have is a.
There's there's a lot of flexibility available in the rig market and so we're just one day, though.
Take advantage that flexibility.
Frankly, we're not sure how many rigs we're going to be running at 2020, and we're going to let the oil market dictates that.
Yeah. The reason I put that comment in about.
What we think the U.S. 2020 year over year oil gross is a is going to be considerably less than what people are currently forecasting.
Is that.
You know I I still think we could see an upside surprise in.
In the oil market tightening in 2020.
And we want to be or at least have the potential to take advantage of that.
Oh on the other hand, a you know you've certainly got all this China noise going on with the trade War.
So so I would say I mean, we could run five rigs we could run as many as seven rigs are in 2020.
And we probably will not make that decision.
Until.
Until you know January of 2020, and the you know the the rigs are available we can pick them up on a moment's notice.
So we're just going to hang on hang loose and and defer that decision and it will be.
A function of a of really what we perceive the oil market to be.
Likely it at year end or or in January .
Okay I appreciate that context and as my follow up question, maybe for Sean I don't know.
Kind of slipping to half an extra question here, but you know with that.
Two things one the recent well performance has been very strong.
Can you talk about is there something specific in your completion, that's that's resulting in that or is it you know the with it better targets that you are looking at sort of the question in my extra bonus half question is on that rig you drop was there was there a cost associated with that or did the contract already roll off.
The second part of that question is easy one on a contract perspective, we have always talked about rig flexibility and the way we layer in our rigs and rig contracts is that we have the ability to add or drop a rig on a quarterly basis and so that was just a timing perspective that was the right time to that go with that rig. So there's no penalties associated with that the contract expired and we decided not to renew it.
With the point that we are very disciplined on our capital and we want to make sure that we are doing everything in our power to stay within our capital guidance range. The first part of that question.
And do better at.
On top of that we are doing more pad and co development and so.
Bringing these wells on simultaneously the more.
And a co development basis is certainly enhancing our production results as well and we continue to drill longer laterals as well. So all of those things I think are incrementally adding to well performance.
Appreciate it thanks.
Your next question comes from the line of Irene Hass.
From Imperial capital your line is open.
Yes, I would like to explore the comment that you made earlier that you'll be spending towards the higher end of the capex and could we get a little color regarding third quarter spending in the fourth quarter spending with third quarter be kind of flat with second and then with a little decline in full force with dropping one rig.
Yes.
Comments I could give you will.
Really relate to.
Just a general thinking.
Related in terms of ducks.
We're going to just monitor again the oil price.
In the history of Cdaf, which is only three years, we'd never created any ducs.
There is a possibility in the fourth quarter.
Again, depending on the oil price, depending on where we stand on our capex level, we might create a few ducks in other words, we may just.
Elect to.
The drill some wells not completed during the fourth quarter.
So.
The fourth quarter would be the one where we might flex more on our capital budget as opposed to the third quarter.
And it would be a function of whether we elect to work to create any ducs or not so.
So that's that's really the.
The key inflection point, if we elect to.
To pull the trigger on things.
In terms of.
The number of the dollar number that we might save for we will save by by dropping that one rig.
Essentially for four months, although Georgia, Sean do you want to give a dollar amount as with it might save for the four months.
Sure I think the impact of that.
Drop rate mark could be anywhere from $30 million to $50 million for the year. The other thing the other color I'd add to marks comment on the facilities and infrastructure side.
Is that we do expect that to decline from the first half to the second half.
Really driven in large part by.
By a decline on the facility side of that.
And we're essentially going to be flowing more new wells into existing facilities in the second half of the year than we were in the first half of the year.
And Thats, certainly going to going to benefit the capital profile.
So if that's the case would you still probably have to have done a really good job of not not tapping your revolver, which you probably need to do some of that in the second half even with.
Of fuel rigs.
Yes, I would expect in the second half of the year will be borrowing under the revolver.
We had $28 million of cash at 630, and it was undrawn, but.
I think thats, a thats a reasonable expectation that we would start to draw in the second half.
Okay, great. Thanks.
Your next question comes from the line of Gabe.
Dollar from Cowen Your line is open.
Hey, good morning, everyone is kind of already hit on in terms of a 2020, but but was curious.
You know given the efficiencies if you stay with with five rigs.
Throughout the course of 2020 give any efficiencies on both the drilling and I guess the completion side in terms of stages per day do you think you could still get off the same number of turn in lines. In 2020, just just given those efficiencies that you highlighted.
I hate to give any projections gate and the 2020 in terms of how many wells we might drill a complete.
I mean that the trend is.
He is obviously.
Better than that and what we projected at beginning of this year in terms of you know days per per well per rig.
But at this stage.
I really don't want to.
You know dance around the question, but projections for what we're going to do on production growth. There are number of wells, we're going to get done in 2020. It's it's frankly, it's just too soon to tell I mean that the oil price as you know has been.
All over the map in.
We just don't want to get hung out trying to give you a number at this early date and then have to walk back that number.
In in January or February . So so we're just not going to give any numbers at this stage.
Okay understood. Thanks, Mark.
And then I guess, just a follow up on the development side the.
The dot com pilot.
And the third the three benches of the bone spring could you just maybe talk about how that kind of fits moving forward into development with the upper zone to the Wolfcamp.
Thank you.
Yes, Sean I want to feel that.
Sure. Thank you.
Were obviously very excited about what went on at the duck on pad. So what we wanted to do there was test three zones vertically stack. So all three of those wellbores are essentially right on top of each other and what we're looking for is to ensure that there is no vertical communication and it looks like there is nothing there. So that's great.
What that really implies is that each one of those reservoirs can be developed fully at any point in time without having to necessarily couple those wells are a couple of those zones going forward. So it gives us a lot of flexibility and those areas to develop the bone spring at whatever pace, we elect to going forward.
Similarly, if we were to put a a wolfcamp a well underneath that I think we would see some similar types of results. Although obviously the the wolfcamp out here is kind of a secondary target relative to the bone spring so.
Very excited about bone spring results and I think thats, probably what you'll see us mainly focused on in the near term.
Okay, great. Thanks, so much for the color guys.
Let me let me just add one other thing there we.
We have a note in the IR slides, we released yesterday afternoon.
That.
Our spacing in Texas.
Is.
His basic spacing is 880 feet and obviously with some of the other earnings calls that have come out this quarter.
Everybody's concerned about spacing.
That the 880 feet, we relate to two Texas, which we think is the most conservative spacing.
In in the Delaware, Texas of anybody.
The new Mexico spacing that we look at although we don't reference around as slide is similarly, conservative I mean, whether you're talking about the wolfcamp or the bone spring.
That same 880 foot minimum spacing is.
Could be applied there also generally in the bone spring, we're looking at 880 foot to 1000 foot spacing.
In some cases it gives up to.
1300, 20 foot spacing.
So.
I would say, it's probably not an overstatement to say that the spacing we use.
In the Delaware, whether it be in Lee County over in Reeves County.
Is probably the most conservative of of any company in the industry. So hopefully that would give some comfort to.
To anybody who chooses to.
To invest in C. diff.
That's great. Thanks Mark.
Your next question comes from the line of Neal Dingmann from Suntrust. Your line is open.
Good morning, all.
Good for you or Georgia, Sean Im just wondering how do you all think about balancing your optimal size pads.
With the particular sort of spin when you when you balance that against cash flow during a particular period or looking at your leverage from just wonder, how you sort of balance or or tie those things together.
Yeah, let me take a crack at that.
Yeah, we.
It really goes back to this you know this parent child issue, where their communication issue in the in the Permian and.
You know, we we started addressing that a couple of years ago and.
I think it.
You know the comments, we made a couple of years ago. He is a proven pretty prophetic as you've seen company after company.
Likely reluctantly.
Admit that they're having to deal with some sort of communication or parent child issues certainly you've seen it in this series of earnings calls that have come out.
We look at it more on a technical basis and on a.
Capital commitment basis, and I think your question relates to particularly these large cube developments that.
That you've seen some of them just haven't worked out too well recently.
Our view is we kind of go to.
Many developments are four to six well.
Developments and it really doesn't have anything to do with the amount of capital committed a where you talk about you know do we want to commit vast amounts of capital before we get any production back. It really is based on a technical efficacy of it and.
And I would point you to the Red rock as a.
As an example here.
We work everything from the technical side out and we just feel like.
For our acreage spread the best way to develop it is to go at it was you know four or six well kind of packages.
And and really works the heck out of it technically to minimize the parent child or communication issues, whatever you want to call. It.
And.
And go at it that way.
And and that's why we highlighted the red rock, particularly in Reeves County this quarter.
To show that.
At least there we have a.
You know we minimize the.
The interference issues and hopefully that sets a template for us as we go forward. So as you as we go forward for us.
Don't expect just hear us highlight.
Of.
Q type developments or make acute developments expect us to highlight more of them.
Four wells six will maybe eight well kind of a multi zone developments on a go forward basis Neil.
Okay, and then just one last one and I'll, let me come through you guys thought about this.
I know your W. text talked about a buyback given other REIT irrationality of the market and certainly you know your stock is by far no different here.
Given given that point you know.
Is there anything that such as any sort of near term shareholder return or say something different you are considering given how rational the smarts to appear in today.
Yeah, I mean, we love the you know we'd love to announce it we're considering a buyback and given the market you know that would probably give us some near term bump in the share price. If we just even hinted about a buyback but.
But frankly.
You know, we pay more attention to our leverage ratios and.
I just don't think we're a company that's got the the proper leverage ratio given our cash flow out spends too to be considering a buyback at this time Neil.
It's all right guys tried sir.
Okay very good thanks, so much.
Your next question comes from the line of Derrick Whitfield from Stifel. Your line is open.
Hi, good morning, all and congrats on a strong quarter enough Dan.
[noise], perhaps for marker Sean your northern Delaware, while results have been exceptional today to what degree could you shift activity from the southern Delaware to the northern Delaware.
Yeah.
Yeah, Derek I mean, youre right Weve been very pleased with our Uh huh.
Our northern Delaware results Saver.
They've outperformed any any of that.
You know pragmatic expectations that we have had in that area.
And so we are implementing.
Pretty much immediately shifting one of our rigs from from Reeves to to Lee County, So we're going to end up with a ratio on a go forward basis here essentially three rigs in research to in in Lee County.
And.
Yeah. We would you know we're not going to expect results prospectively of of wells like the Theresa well, which we recently had.
You know that would be too optimistic to program that.
But.
Frankly, we expect that the we're probably going to continue to beat our type curves with our Lee kind of results.
And if you project over the next six to nine months I.
I think we will have some.
Upside surprises.
Will continue and we will just have a continuous flow of good news, particularly coming out of Lea County, and that's not to denigrate.
The Reeves results are pretty good too but.
But the.
If I had to just guess I'm going to guess that we're going to have more headline wells over the next Oh, let's just say six to nine months coming out of Lee.
Dan Reeves, just just due to the rock quality would be my guess.
That's great and then as my follow up perhaps for for Sean at a high level.
Where are you seeing the greatest efficiency gains in your completion operations and.
What are your leading edge DNC cost per lateral foot based on first half efficiencies.
So on the on the completion side you know a we've done a good job year over year that we talked about a 25% increase and number of stages completed a year over year per day, which is great and a lot of that honestly is kicking over rocks its managing folks in the field. It's having your field personnel really engaged with your dedicated frac crews and all of that synergy really works out to your advantage and just looking for any opportunities to decrease downtime and increase efficiencies I can say that it's one thing that all of a sudden we've gone to a certain method that allowed us to increase our efficiency. There, it's really the blocking and tackling and just looking for small opportunities that add up to incremental gains overtime.
On the per foot cost, we really havent released or anything along those lines. So I think we're certainly doing better and we've seen a nice decreasing cost year over year at least from year end. Two current were down about 5% as we talked about in the release and we do expect to see continued downward pressure throughout the balance of this year. So I think thats the best I can do well on this with that question.
Thanks, its very helpful.
Mr.
Your next question comes from the line of will Thompson from Barclays. Your line is open.
Hey, good morning, guys.
Mark maybe to piggyback on on some on Neal's question clearly the market has started to bifurcate the companies that can grow within cash flow and those that can regardless of balance sheet quality I'm sure Mark eight year old from you would have been pretty excited at the prospect of acquiring premium failure, Delaware acreage at Centennial is current dollar per net acre.
Given that the C. Diff model was really based on a higher oil price whats the roadmap and your current thinking to extract value from your acreage clearly feel strongly about protecting the balance sheet and correct me if I'm wrong, but my sense is you're not interested in pursuing merger vehicles.
Any additional color on that would be helpful.
Yes, it will.
Yeah. It's.
Tough situation right now to.
Since we are in a situation where.
It it's not likely we're going to be a.
Even cash flow neutral by 2020 and less the less you project the more optimistic oil price and the futures market is indicating.
You know I will say that the.
You know our hard line on debt to cap is 30% and so we're going to have to manage the company.
Within the within the limitations of that hard line.
On there.
And so with the you know.
So what we're going to have to do is just continue the efficiencies that we have.
And.
You know the.
We originally designed to company to have very very high production growth rates.
Through 2020.
We've clearly had to change that strategy to more modest production growth rates and and I think we're just going to have to manage the company with more modest production growth rates.
Until we can reach some sort of cash flow neutrality and that's.
That's our current strategy.
I don't understand why relative to our peers.
Our implied acreage value is.
Is is so low.
Because clearly if you just look at our well results.
Whether it's on Reeves or Lea County.
It should be obvious to anyone that our acreage is at an absolute minimum.
Equal to or to pretty much everybody else's acreage and I would I would argue it's probably better than in most of the other acreage. So hopefully with time, we'll get at least that.
Implied back into our valuation.
That's the best answer I can give you at this time.
Thank you Mike that's helpful and then marker Sean.
Centennial now plan to turn the transition to a second rig in new Mexico.
Your position in new Mexico is somewhat smaller and a bit more scattered than your southern Delaware, but clearly you're pretty excited about the recent bone spring results.
Maybe help us understand where you are in terms of infrastructure build out new Mexico.
Would you consider small bolt ons I know you've been focused on organic inventory growth, but maybe as opportunities do continued land trades.
Plus there will be helpful. Thank you.
Yes, John .
Sure I think it's a fair question and one of the reasons, we've been a little bit slower to go towards full scale development into Mexico is that we wanted to make sure we had our infrastructure in place oil gas and water to make sure that our costs and were being efficient with the dollars that we spend both capital and expense flies out there at this point in time, we've gotten to the position we feel a lot more comfortable with the infrastructure out there and all three of those streams such that we feel confident that having a second rig into Mexico is the right thing to do at this point in time and go towards more of a development mode. As you said the results of their certainly a warrant additional activity. You mentioned is scattered nature of it I think we've done a pretty good job actually of piecing that acreage together pretty well and we've done some swaps and trades that have helped US go from single mile laterals to some longer laterals in that area and I think you'll continue to see that going forward from a small bolt on type of question. You asked I, we're always looking for opportunities there to add acreage.
That is adjacent to our positions, whether it's in Texas or new Mexico, So long as their AD.
Competitive prices and I think you'll see us continue to look for those opportunities going forward.
Okay. Thank you guys.
Thanks will.
Your next question comes from the line of assets in from Bank of America Merrill Lynch. Your line is open.
Thanks, Good morning, guys Mark I was wondering if I could ask you about your new role as the chairman of Schlumberger.
Historically in prior occasions, you have been an advocate of in house GNP innovation bypassing the service providers do you see that model changing is something different in the new world as we deal with issues like parent shines.
And while you're on that topic any thoughts on where you see the next big innovation to drive shale growth.
Such as well as the Digitization or AI.
Yes that that question I mean my role is.
As chairman of the Schlumberger is I mean, non executive chairman of Schlumberger. So that's.
That's a rule that is.
Limited scope really I chair of the board meetings. The Schlumberger is basically my function there so.
The issues that exist in the shale development the parent child issues interference issues I think is going to take a lot of technology to six I think that the service companies are going to have to it's going to have to be a joint.
Effort.
With the service companies and also with the S&P companies to them to solve that problem.
Okay. Thanks, Mark yes.
Your next question comes from the line of Kashy Harrison from Simmons Energy. Your line is open.
Good morning, everyone and thank you for taking my questions.
Yeah Kashy.
Okay. So in the prepared remarks, there was some commentary on a 5% reduction in well costs and in the presentation. You highlight that well performance is tracking <unk>, 10% above 2018 levels and so if we if we take both of those two things into consideration and then.
We take what I imagine are lower base the clients exiting 2019.
I was wondering if you could just help us think through what a maintenance DNC estimate might be to hold the.
The 2019 exit rate flat through 2020.
Yeah, Kashy I mean, we've we've always shied away from providing.
Numbers on maintenance.
DNC.
And I think we thrash through that issue in some of the previous earnings calls there.
So all I can point you to is directionally.
In that.
We've we've shallow without our decline a bit.
You've seen that come this year are you seeing that the.
In terms of our low he costs relative to last year have actually come up a bit desk, because we're spending more money on workover rigs and things like that but it has hedged slightly shallower room our decline rate.
And you know we are seeing.
Gratifyingly.
Relative to our type curves the wells are a bit better. This year. So the only thing I would say is directionally.
Everything is moving in the right direction.
That would make maintenance capex.
Lower next year.
Than one might have forecast at the beginning of the year.
But other than that we're not going to give any quantification as to what what that is.
Excepted Directionally things look a bit brighter on that front and they would have six months ago.
Gotcha, Okay. That's that's helpful at least.
But.
And then maybe switching gears for my follow up question.
So this year I think.
Facilities infrastructure and other capital was about 17% of the total budget.
What's can you kind of help us think through the flexibility in that number. So for example, lets just say you decided to lower activity next year would we expect expect that percentage to go down or maybe would we expect the absolute number to go down just just to help us think through the evolution of that facility spend depending on what level of activity you're running at any given time.
Yeah, George and you want to give some insight on that sure. Thanks, Kashi I'd I'd say on infrastructure.
You know, obviously, we're not providing guidance for 2020, but I will say that we are and have been in 2018, and 2019 investing pretty heavily in our SWT system.
And we've got a significant amount of capacity on that system in Reeves County.
And I would anticipate.
That that type of spending would decline from 2019 to 2020 because of the historical investments we've been making.
On the facility side.
You know a little bit.
Probably a little bit more of a steady pace relative to to what weve seen although as I pointed out in my earlier remarks, the dynamic were seeing as we've invested in more centralized tank batteries and things like that is that we're able to turn new wells into existing facilities and thereby reducing the capital burden on our go forward spend and so I would expect that that would continue.
Into next year and in fact accelerate as we become a more mature company over time.
Got you that's it for me thank you.
Your next question comes from the line of Kevin Maccurdy.
From Heikkinen Energy your line is open.
Hey, Good morning, guys and this is just a follow up from an earlier question Mark given your limited role at Slumber J does that lead to any changes in house continually manage.
No no Kevin not at all like say them at a time I spend at Schlumberger is very de Minimis. It's it's a.
Doesn't affect anything and wait.
Centennial is managed.
Great. Thanks for clarifying that and congratulations on the good quarter.
Thank you.
Rents. This is Hayes do we have any more questions in the queue.
[noise] telephone questions at the moment, Sir and great wall I just want to say thank you for everybody for joining in joining us on todays call feel free to call me. If you have any questions and we can end the call now. Thank you very much runs.
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