Permian Resources Corp

NYSE:PR

Earnings Call Transcript 2019-Q3

[Operator]

Good morning, and welcome to Centennial Resource Development's 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 19, 2019, by dialing [phone] and entering the conference ID number 3066178 or by visiting Centennial's website at www.cdevinc.com.

At this time, I would like to turn the call over to Hays Mabry, Centennial's Director of Investor Relations for some opening remarks. Please go ahead.

[Hays Mabry, executive]

Thank you, Michael, and thank you all for joining us on the company's third quarter 2019 earnings call. Presenting on the call today are Mark Papa, our Chairman and Chief Executive Officer; George Glyphis, our Chief Financial Officer; and Sean Smith, our Chief Operating Officer.

Yesterday, November 4, we filed a Form 8-K with an earnings release, reporting quarterly earnings results for the company 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 homepage or under Presentations at www.cdevinc.com. I would like to note that many of the comments during this earnings call are forward-looking statements that involve risks and uncertainties that could affect our actual results and plans. Many of these risks are beyond our control and are discussed in more detail in the risk factors and forward-looking statements sections of our filings with the SEC, including our annual report on Form 10-K for the year ended December 31, 2018.

Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results -- excuse me, actual results or developments may differ materially. We may also refer to non-GAAP financial measures that help facilitate comparisons across periods and with our peers. For any non-GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation, which are both available on our website.

With that, I will turn the call over to Mark Papa, Chairman and CEO.

[Mark Papa, executive]

Thanks, Hays. Good morning, and welcome to Centennial's 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 well results. 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.

[George Glyphis, executive]

Thank you, Mark. Centennial's operations continue 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 averaged slightly over 42,000 barrels per day and average net oil equivalent production totaled approximately 76,300 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 event and will decrease significantly in Q4. Inclusive of basis hedges, Centennial's realized oil price was $48.71 per barrel for the quarter compared to $54.45 in Q2.

Shifting to unit costs. Cash G&A and DD&A were essentially flat to the prior quarter at $1.81 per barrel and $16.06, respectively. LOE increased to $6.03 per barrel as a result of higher electricity costs during the month of August, in addition to increased chemical and equipment costs.

GP&T expense increased to $2.97 per barrel due to lower reimbursements associated with the subleasing of our natural gas firm 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 42,250 Boe per day and total equivalent production guidance is being increased by 5% at the midpoint to 74,750. 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 are also increasing the midpoint of our completions guidance by 5 wells to 75 gross operated completions given the efficiencies seen to date. Additionally, we are increasing the midpoint of LOE by 14% to $5.30 from $4.65 and are reducing DD&A and cash G&A by 3% 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 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 LOE.

Turning to capital spending on Slide 8. In early September, we reduced our rig count to 5 from 6 since we have confidence in achieving our planned activity levels with fewer rigs, given the accelerating efficiencies we are seeing in the field. For the quarter, we spud 21 and completed 17 gross wells compared to 23 and 20, respectively, during the prior quarter.

D&C CapEx was approximately $160 million in Q3, an 11% decrease from Q2. Notably, this marks the fourth consecutive quarter of declining D&C 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 have 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 saltwater disposal system in Reeves County, which is detailed on Slide 10, we are exploring a potential monetization, which, if consummated, would provide significant capital resources that can be utilized for debt repayment or various investment opportunities. A 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 in land capital during the third quarter, which brings us to a cumulative total of $35 million year-to-date. As a result, we plan to pair 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 of 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, our $1.2 billion borrowing base was reaffirmed by our bank group. With $120 million of outstandings at September 30, 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 30 was 24%, and net debt to LTM EBITDAX was 1.7x.

With that, I'll turn the call over to Sean Smith to review operations.

[Sean Smith, executive]

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 we turn to individual well results, I'd like to take a moment to detail some of the operational improvements we're seeing firsthand in the field which are shown on Slide 7. 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 continued to increase the number of stages stimulated per day. Compared to last year, we increased our average stages pumped per day during the quarter by roughly 30% to over 6 stages per day, occasionally achieving 9 stages per day. The increase is driven by our employees on the ground, driving efficiencies in the field.

Additionally, we have 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 has translated into an approximate 22% reduction in total well costs for the quarter relative to our initial 2019 cost assumptions, and the trend line indicates further reductions may be 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 opportunity to lower costs as we head into 2020.

Now turning to results for the quarter. Centennial ran 6 rigs for a majority of the third quarter before dropping to 5 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 5. In Reeves County, we brought online 2 co-development tests involving the Third Bone Spring Sand. The Barracuda 3-well pad was drilled using approximately 10,000-foot laterals in a stacked, staggered pattern, combining 1 Third Bone Spring Sand well with 2 Wolfcamp Upper A's.

The Wolfcamp A wells were spaced at 880-foot spacing, which is our normal spacing for this area. The pad delivered an average IP-30 of approximately 1,900 barrels of oil equivalent per day and produced over 215,000 barrels of oil during its first 60 days online.

The Doc Hudson package also contained 1 Third Bone Spring Sand well paired with 2 Wolfcamp upper A's. The 6,000-foot lateral wells achieved an average IP-30 of almost 1,600 barrels of oil equivalent per day or 216 barrels of oil per day per 1,000-foot of lateral per well.

The Barracuda and Doc Hudsons are important delineation tests. Not only do they further validate the co-development of the Wolfcamp Upper A and the Third Bone Spring Sand, but these wells represent our southernmost test to-date of the Third Bone Spring Sand on our Reeves county acreage, effectively expanding our sweet-spot farther south than originally 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 Moore County. Throughout 2018, we dialed in our efforts, successfully pairing this zone with the Wolfcamp Upper A.

Earlier this year, we pushed the Fairway West into our Miramar acreage with a strong fundamental well. 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 0 entry costs.

Turning to New Mexico. Centennial completed the 2-well Asadero State pad, targeting the Second Bone Spring with approximately 7,000-foot laterals. These wells delivered average IP-30s of approximately 1,300 barrels of oil equivalent per day, 89% oil and continue to produce over 1,000 barrels of oil per day, 60 days after initial production.

We continue to be pleased with the well performance on our New Mexico assets. Now that we've established production from 6 different zones, built infrastructure and put together contiguous land positions, this area is ready for additional development. Thus, we shifted a second rig to New Mexico in August and recently transitioned from drilling one-off wells with single mile laterals to longer multi-well packages across multiple horizons using longer laterals.

I'd point you to the bottom right-hand side of Slide 6. As you can see, our average lateral length year-to-date in New Mexico has increased 41% versus 2018, while our total cycle times per 1,000 foot of lateral had decreased 46% over that same period.

We also recently implemented a water recycling program in Lea County. This not only lowers our overall completion costs, but also positively impacts LOE. 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 want to touch on our exposure to federal leasehold, as I know this has been a topic of late. Out of our roughly 80,000 net acre position spanning both Northern and Southern Delaware Basins, Centennial has only 4,000 net acres or approximately 5% located on federal lands, all in Lea County, New Mexico.

So with that, I'll turn the call back over to Mark.

[Mark Papa, executive]

Thanks, Sean. Now I'll provide a few thoughts regarding the oil macro picture and relate them to Centennial strategy. At a September Investor Conference, I predicted that 2020 total U.S. year-over-year oil growth would be 700,000 barrels per day, which at that time was considerably below consensus. Given additional data, I now think that 2020 year-over-year oil growth will be roughly 400,000 barrels per day, which is below current consensus.

Per the EIA 914s, U.S. production has been essentially flat for 9 out of the past 10 consecutive months, and it's likely to slightly decline over the next 6 months. Most people will ascribe the low U.S. growth to capital discipline. But I think the larger reason is what I've been talking about for several years, the shift to Tier 2 and 3 drilling locations in all shale plays and increasing parent-child issues in the Permian.

I'll also note that this is likely not just a 2020 event. I believe U.S. shale production on a year-over-year growth basis will be considerably less powerful in 2021 in later years than most people currently expect. I'll 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 a future domestic industry that we believe will be growth challenged. This quarter was another one that typified CDEV. We 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 of this quarter was a significant improvement in our D&C costs relative to early 2019. This is occurring on both the drilling and completion side, and bodes well for our 2020 capital efficiency.

In my mind, there's never been a question regarding our well quality. From inception, we've always been in the upper half ranking in the basin. For those fixated on cash flow outspend, we're investigating monetizing our SWD 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 a final thought. This year, we've raised our production guidance twice without increasing CapEx, which implies that CDEV's 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&A.

[Operator]

[Operator Instructions] Your first question comes from Scott Hanold from RBC Capital Markets.

[Scott Hanold, analyst]

The, I guess, opportunities, do you monetize this saltwater disposal system. Can you give us a little bit of context of what you all have invested to date on that?

And I think you mentioned that you're potentially looking at building it out a little bit more to -- on some of the recycling in Texas. Would that -- with the recycling and disposal, would that all be put together, packaged together as one? Or what is the size and plans for that?

[Mark Papa, executive]

George or Sean, you want to field that?

[Sean Smith, executive]

So on the -- how much we've invested in this system, obviously, I think that's -- we can't really talk about that as we're just starting the process to pull the information together and working with various banks to select who might be marketing for that. So can't really give out those costs right now as we're just starting the 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 in New Mexico from a recycling position and think that there's some real opportunity to cut costs, both on the capital and the LOE 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 saltwater disposal divestiture somehow and 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 that system.

[Scott Hanold, analyst]

Okay. Great. Understood. And Mark, maybe a big picture, obviously, it sounds like you're constructive on the oil macro in the next few years. You guys are down to 5 rigs, but I've seen some efficiencies. I mean, could you give us some context? I know it's probably too early for a 2020 budget, but some context on how you think about activity and outspend in kind of that view?

[Mark Papa, executive]

Yes. I'll give you some general context, Scott. #1, the 30% debt-to-cap is still a hard guideline for us. That's kind of the primary guideline. So we're not flexing on that in terms of what we do. I'm not going to provide any guidance as to what we're looking at for production target in 2020 at this time. But the primary guideline will be -- we're not going to exceed the 30% debt-to-cap number.

What I will say is that we've never mentioned the disposal of the SWD assets up to this point, although other companies have looked at and done that prior times. If you look back at the background of when I was running EOG, we never monetized any of our assets in-house, any of our processing assets or anything like that. We never went for any of those particular monetizations into MLPs or anything. And so we followed the same philosophy here. I've always, up to this point, really believed that there's a better valuation, keeping those in-house. But times have changed here and clearly, there's an investor fixation with cash flow outspend. So looking at this potential cash flow outspend that we're faced with possibly in 2020, we are saying, well, one way to solve that problem is to monetize SWD. And in fact, it would potentially solve it 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 growth mode on the production side. So we're in the early stages of looking at monetization, but it gives us additional flexibility. And I think up to this point, people viewed CDEV in 2020 as -- well, we're either going to have to bust the 30% debt-to-cap in a $55 oil world or we're going to have to show 0 growth or very, very small production growth. And that's been apparently pretty unappealing to the average investor. And this is another weapon that we have that can still allow us to stay within the 30% debt-to-cap 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 U.S. production growth, which may affect the global oil price, I won't predict that one way or another, it gives us, I think, a potentially a good setup, and I think should allow investors to view this in a more constructive light for both 2020 and 2021.

[Operator]

Your next question comes from Neal Dingmann from SunTrust.

[Neal Dingmann, analyst]

Mark, my next question, I guess for you or Sean. I just -- you've done a great job particularly here in the last quarter to -- on bringing well cost down. I guess, a pretty broad question. When you see, I guess, just the amount of room you see that for -- when you look at 2020 for additional well cost improvement, both just on the operating side and then all the way, I guess, including LOE and everything else, all the way to the production side?

[Mark Papa, executive]

Yes. Let me address on the capital side, and then I'll ask Sean to address it on the OpEx side. Probably one of the most pleasant things we've seen throughout this year is a significant decrease on -- basically, on the well cost side, the D&C side. I mean, most of the wells we drill now are 7,500-foot laterals. That seems to fit our acreage best. So just relating to the 7,500-foot laterals. And that's why we said the costs currently are down 22% from our initial 2019 estimate. But I would say there is room for those costs to go down further than 22%. And some of our recent trending wells indicate that if the trend continues, that the 22% is not the maximum delta that we're going to see. It's occurring primarily on the completion side, but also, clearly, on the drilling side, too, but the biggest portion of that is coming through on the completion side.

And I would say, if we stay in a $55 oil environment for 2020, the likelihood is we will see further reductions over and above the 22%. That appears to be the trend that we're on. And again, when you view -- when CDEV is viewed as a company that earlier in the year, we reviewed as a company that, my gosh, for the capital, we're spending. There's no way that we could have any growth and stay within certain financial limits. I think that needs to be reevaluated based on the results that we're 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 we're an outlier.

On the OpEx side, let me have Sean address that, particularly some of the things on the LOE side, which I know is a key question.

[George Glyphis, executive]

Yes, Mark, it's George. I'll go ahead and take that. As you saw, we did see some increases in our LOE 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 had some increases in terms of chemical costs and 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 will be operational midyear. And what that will do for us, it will reduce our reliance on generators for our ESP or pumps. And thereby, increase our efficiencies, increase 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're addressing these kind of one by one in an effort to mitigate the cost increases we saw in Q3.

[Neal Dingmann, analyst]

Great details, guys. And then just one last follow-up. You know everybody likes to have the, I guess, the most linear type production growth and just what with the 5 rigs running next year, how should we think about that on a quarterly basis versus having the larger pads and maybe blocking up some completions, et cetera?

[Mark Papa, executive]

In terms of what our production growth might be with 5 rigs, is that your question, Neal?

[Neal Dingmann, analyst]

Yes. I mean, I'm just wondering more on -- everybody loves to have it as smooth as possible where we kind of grow equally each quarter. I'm just wondering, Mark, when you look at -- is that possible, I guess, I'm asking, given the need for the efficiencies with the larger pads?

[Mark Papa, executive]

Yes. Well, I guess, first part of that is we haven't really decided whether we're going to run 5 of it, exactly how many rigs we're going to run next year. So we're not committing 5 rigs. Our rig contracts give us a lot of flexibility. So we'll give you some context on that in the February call as to how many rigs we plan to run specifically.

In terms of the number of wells per pad or whatever that we plan to run, we're still going to stick with not going to the giant cube-type drilling sequences or anything like that. Generally kind of 4 wells per pad, 3 wells per pad, 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 that would be more typical of some of these things like the dominator pads or some of those kind of things. So I would say a small amount of lumpiness quarter-to-quarter, but less than you might see from some of the other companies that are going to the cube type, large cube type patterns.

[Operator]

Your next question comes from Subhasish Chandra from Guggenheim Partners.

[Subash Chandra, analyst]

I just want to ask a lot of questions a little bit differently. The current utilization of those water assets, do you have a number, what your current saltwater disposal volumes are?

[Mark Papa, executive]

George or Sean, you want to fit in?

[Sean Smith, executive]

Subhasish, this is Sean. I hate to keep using this kind of excuse, but we've just gotten into the process here. And so I really don't want to give out too much information until we have our bank on board and potential suitors have the information in hand. I will say that we are currently producing over 200,000 barrels of water per day as a company. Our infrastructure system in Texas has permitted capacity in the ground, 200 -- I guess it's 280 -- 260,000 barrels of capacity in the ground with permits for another 120,000 barrels. So those are the kind of numbers, I guess, I feel comfortable giving out right now.

[Subash Chandra, analyst]

Okay. Yes, no, got you. And then could you share this number, I guess, of the facilities expense in 2019? I think the budget range of 120, 160, how much of that was for the water?

[George Glyphis, executive]

Yes, we haven't disclosed that, Subhasish. What I'd guide you to is if you look at our 2018 spend and 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 should give you a sense of the split between those 2 buckets of capital. And I think for this year, not exact to that number, but I think directionally, we'll be similar.

[Subash Chandra, analyst]

And this would count as facilities or?

[George Glyphis, executive]

This would be -- it has to be the infrastructure spending. Yes.

[Subash Chandra, analyst]

Okay. Got you. And just one for the presentation. I think on Slide 6, I just want 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 6 on the far right graph there, 7.9 goes to 4.3 per 1,000 feet, is that days per 1,000 feet?

[Sean Smith, executive]

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 a 10,000-foot well, just using it as an example, would have taken 79 days from spud to initial production in 2018, whereas that same 10,000-foot well would take 43 days year-to-date 2019.

[Subash Chandra, analyst]

Got you, from spud to sales. Yes, that seems really, really fast. So I wanted to make sure of that.

[Operator]

Your next question comes from Charles Meade from Johnson Rice.

[Charles Meade, analyst]

Mark, if I -- I appreciate the comments you gave us some coordinates for how you're thinking about '20, but I wondered, if I could just perhaps get you to elaborate, not so much on numbers, but priorities for '20? I get that your hard metric is that 30% debt to cap, but what would come after that? Would it be -- is it a priority to keep production flat if possible? And what's the time line? If you have any time line to meet what you call this obsession or this picture on free cash?

[Mark Papa, executive]

Yes. The overall riding comment, I guess, the overriding strategy for CDEV goes back to the macro, Charles, just to set it in -- from 30,000 feet. I believe the U.S. is going to be in a growth-challenged environment in the 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 there are 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, '22, '23, '24, '25 and 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 what's the relative quality of the prospect inventories of each company. And our goal is to have a good prospect inventory. Hence, the slide we've shown on our expanding Bone Springs, Third Bone Spring prospect inventory as one example in the attachment this quarter. And so we -- and one would assume if U.S. year-over-year growth 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 CDEV to be in a position to be able to grow at that time. Now if 2020 is not when global oil prices increase, then we will probably respond accordingly and not strive to have significant production growth. And we'll gauge our capital program accordingly.

But when global oil prices become more robust, we will then adjust our capital program to show production growth and that will likely be in a world where other companies will be growth challenged. And they'll be growth challenged mainly because the shale plays are going to not be as prolific as people are currently alleging that they are. So that's a general point, and we're not going to allow this company to be heavily indebted such that whenever the oil market improves, 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 says, we don't want to go over that amount, 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 go over that red line until we see oil prices improve. So hopefully, that gives you a little bit of our underlying philosophy of the company.

[Charles Meade, analyst]

Mark, that's actually really informative for me. So I appreciate you taking the time to answer it that way. It also sets up the second question that I had, which is about the Third Bone Springs there as you move south in Reeves County. In my understanding, you've always known that zone is there. There's just -- the question was whether it's perspective or not? And now 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 change your view about maybe as you go up in the column, to the center you have Second or First Bone Springs in that same positive share?

[Mark Papa, executive]

Yes. It -- the answer -- short answer is yes, Charles. It changes our view and makes us more optimistic that the Third Bone Spring Sand can be pushed farther to the south on our acreage. I mean, if you look at the Slide 6 or whatever it is.

[George Glyphis, executive]

Slide 5.

[Mark Papa, executive]

Slide 5 there, it certainly makes us more confident that, that orange ellipse, as time moves on, can be further pushed to the south. Now that the rock changes in terms of -- what it looks like stratigraphically as you move to the south. But it's our hope and our belief that we think we can expand that, and hopefully, maybe across all of our acreage reserve to the south and to the west, as you've seen. So hopefully, within 6 months, maybe that orange ellipse kind of covers all of our yellow acreage there. And it also gives us a little more confidence that farther up in the section that the -- in the Second Bone Spring, that maybe there's a zone here that we can test. We've kind of suspended testing farther up in the section, as oil prices have not been conducive to doing a whole lot of additional testing in the section.

But -- and again, we know right now that in our stock valuation, we're not getting paid for expanding prospect inventory on our acreage. In fact, I think people probably say, are even spending precious capital on doing this, but our belief is that, that's a very wise investment. And at some point, that it's going to be worth its weight in gold, particularly on our existing acreage.

[Operator]

Your next question comes from Asit Sen from Bank of America Merrill Lynch.

[Asit Sen, analyst]

I have 2 quick follow-ups. Just wondering what the leading edge or average well cost average, if you could share with us D&N per foot, either in Southern Delaware or New Mexico?

[George Glyphis, executive]

I think Mark mentioned 7,500-foot lateral as an average.

[Mark Papa, executive]

Yes. We really don't want to give out -- that's kind of like what's our intrinsic decline rate of our production base. Our feeling is if we give out $1 per 1,000 feet or something like it in well cost, all it does is, whoever comes behind us on the earnings call tomorrow or the following day will just say, we'll match that number and top it to show that we can beat whatever CDEV has come out with. So we just prefer to say, we think it's very competitive with what other people are doing. Whether it's the absolute best in the peer group? We're not sure because it's a moving target. So we just kind of leave it. It's a significant improvement. It's showing up in our capital numbers, clearly, and it probably got room to improve further as we go into the fourth quarter and into 2020.

[Asit Sen, analyst]

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've experienced so far?

[Mark Papa, executive]

Yes, good question. George or Sean, you want to explain the oil cut situation?

[Sean Smith, executive]

This is Sean. So for the third quarter, it was a little bit lower in oil cut. We had some production, some wells we brought online in Miramar, which is our higher GOR area, which brought that percent oil down a little bit for 3Q. Fourth quarter, we'll go back to -- closer to what it had been in prior quarters, and we still hold firm our average for the year, I think, is what we have 57% for the year for oil cut. So which would imply in Q4, it's going to be certainly higher than Q3.

[Mark Papa, executive]

Yes, Asit, let me just give you a little color on that. Just as we relate to Miramar, if you just look on that slide on Page 5, just to give you a little color there, Reeves County acreage, the oil cut is remarkably consistent across all of our yellow acreage, except that acreage that's shown in the northwest there. The northwest and kind of like where that strong fundamental well is highlighted if you happen to be looking at that particular slide on Slide 5. That's called our Miramar area, and that is a higher GOR area, clearly. So any time we happen to drill in a quarter, a higher kind of disproportionate number of wells in the Miramar area, our GOR in the next quarter is going to pop up. And so it's a function of how many wells are we brought online in the 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, that will bring the oil cut up relative to it. So hopefully, that just locates it pictorially a little better for you.

[Operator]

Your next question comes from Kashy Harrison from Simmons Energy.

[Kashy Harrison, analyst]

So first off, a quick follow-up to an earlier question. I think you were talking about some of the spend from 2019, that there was a 75% bucket that was associated with facilities and 25% associated with infrastructure. And if it was the right way to think about it entering 2020, that piece that you consider facility spend would be highly correlated with the change in D&C year-on-year? And then we would expect the infrastructure spend to be lower next year due to the monetization of the -- or potential monetization of the water assets?

[George Glyphis, executive]

Yes, Kashy, this is George. The 75-25 split was tied directly to the 2018 spend, although directionally, that 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 centralized tank batteries and things like that and coming into existing pads will probably scale down that spend relative to our D&C capital over time. Infrastructure is clearly a more lumpy category and a monetization of the SWD system, which certainly reduced that on a go-forward basis, very, very significantly.

The power substation is something that is a capital item that's kind of split between this year and next, but that infrastructure bucket would go down very significantly going forward.

[Kashy Harrison, analyst]

So it sounds like non-D&C spend would be or could be materially lower next year then?

[George Glyphis, executive]

Yes.

[Kashy Harrison, analyst]

Okay. 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 a different metric, so to speak. Can you just give us a sense of just CapEx per rig per year, just for us trying to -- as we try to calibrate some capital efficiency numbers entering 2020?

[Mark Papa, executive]

Yes. I don't know, Sean, do we even look at things in that manner?

[Sean Smith, executive]

We haven't -- I mean, obviously, we have the numbers, but we haven't disclosed that type of number.

[Mark Papa, executive]

Yes, I think we'll pass on that one, Kashy.

[Kashy Harrison, analyst]

All right, then. I'll try one more. So I know you're reluctant to provide underlying base decline. So I'm not going to ask for the exact number. But since the rate of growth is slowing, I was wondering, if you could just give us a sense of the relative rate of change entering 2020? So for example, would you expect that base decline to be flat 2020 versus 2019, 5% lower, 10% lower, et cetera? Just some thoughts on the change would be helpful?

[Mark Papa, executive]

Yes, it's -- I mean, it's going to be lower in 2020 probably to the tune of 3% or 4% lower versus 2019. And we've -- I think the one thing you can say is where the stock blew up and everybody kind of got disappointed was in February, where we said we're going to get off the production growth train and slow down the capital program, and everybody said, Oh, my gosh, you must have a horrible decline rate because your production growth is going to be much less than we thought when you cut your capital. But I just go back and say, okay, now we played that through the end of the 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 CDEV 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 has declared a 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 our operating costs are in pretty decent shape. And our plays continue to expand in Third Bone Spring. So overall, this is a pretty good company, really. And if we look at monetizing the saltwater disposal system, suddenly, for the next couple of years, our 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.

[Operator]

Your next question comes from Derrick Whitfield from Stifel.

[Derrick Whitfield, analyst]

For my first question, I'd like to approach the 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 assume you could hold 2020 production flat with 20% less capital? You seemingly have capital costs and base decline factors as tailwinds.

[Mark Papa, executive]

I guess the way I'd answer that without giving a percent is that it will be reasonable to say we could hold 2020 production flat with less capital than everybody, including Wall Street would have expected just 6 months ago, but whether the number is 20% less or not, I don't know. In fact, I haven't even calculated it, Derrick. So I can't give you a quantification. But clearly, with less capital than we thought, the 22% less well cost would imply, I guess, you could back into some number in that range on there, but don't hold me to 20%. But clearly, less capital, that's for sure.

[Derrick Whitfield, analyst]

And Mark, that was the basis, too. It was really just on the 22% capital efficiency improvement. And it just seems like there's a lot of tailwinds supporting your business right now that aren't showing up on your stock?

[Mark Papa, executive]

Yes, I would agree with that, Derrick.

[Derrick Whitfield, analyst]

And then as my follow-up, I'll probably direct this to 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 ban 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?

[Mark Papa, executive]

Yes. And again, this is without having a vast amount of expertise. I'll caveat with that. Yes, if you did get some Democratic administration in there, and they did impose a "frac ban" on federal lands, I think that would immediately go to the courts. And I think that you would have a protracted time in the courts there, and it'd be pretty -- my guess is that would take legislation. So you'd have to have both houses of the Congress that would pass that. So you'd have to assume that Democrats would take over the Senate, too. I think it would be a long drawn-out fight and believe many, many years before that would that would actually occur in terms of mitigation. So you'd be looking at probably 3, 4, 5 years down the road before such a ban would actually get enacted if, if, ever, if at all.

I mean, for CDEVs case, since we only have 5% of our acreage there, we could fairly readily shift away from that 5% acreage, and it would only have a minor effect on our specific situation. So that would be just my off the cuff ideas there. I suspect that would -- the whole thing about a federal ban on fracking on federal lands would probably be one of those campaign promises, it would never actually get enacted. That's my belief.

[Operator]

Your next question comes from Will Thompson from Barclays.

[William Thompson, analyst]

Mark or Sean, can you give us a sense of the contribution from D&C efficiencies and cost deflation in the 22% lower well costs? You mentioned going to larger pads in the North Delaware. Just curious on where you are in terms of maybe zipper fracs and [ SIM ] ops in driving down D&C cost?

[Mark Papa, executive]

Yes, Sean, go ahead.

[Sean Smith, executive]

Sure. Yes, thanks for pointing that out. I think what you'll see on -- in the slide deck on Page 7 really talks about our overall company efficiencies that we've enacted and what you'll see there is, a, longer laterals, higher percentage of multi-well pads being utilized across the board, both Texas and New 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 we're on top of that, from that perspective, but certainly, increasing number of wells per pad to a point, 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 at ourselves as well as the industry on both ends of that, both drilling and completions and look forward to seeing further reduction into next year.

[William Thompson, analyst]

That's helpful. And then I just want to reconcile the 22% lower well cost versus expectations for CapEx that 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 ] range, which is now the midpoint of the revised [ till ] guidance, but you would think the lower well cost would offset this somewhat? So I'm just trying to figure out, if I'm missing something?

[Mark Papa, executive]

Yes. One point there, Will -- yes, 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 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 going to see them in the fourth quarter, and we saw them part of the third quarter. But that's one of the reasons why we're not seeing a massive reduction in the CapEx for 2019 on there. So I think that's probably the biggest explanation.

[William Thompson, analyst]

No, that makes sense. And I guess I misinterpreted that 22% being for the full year. Okay. That makes sense.

[Operator]

And we have reached the end of our allotted time. I will now hand the call back over to Mark Papa for closing remarks.

[Mark Papa, executive]

Okay. Just -- I'll close by saying there's 4 important points I'd like to have everyone take away from this earnings call. First point is that we're clearly seeing capital costs come down dramatically, as we talked about on this call, and it looks like the capital costs still have room to run to come down some more.

Second point is that we have raised production guidance twice in the last 2 quarters, with no increase in our CapEx budget. So there must be something going on within the bowels of CDEV. That's very positive to see that occur, either on our intrinsic decline rate or in the quality of our wells that we're bringing online.

Third thing is that the Third Bone Spring Sand continues to expand on our acreage through our step-out drilling and even though people who aren't giving us any value for that right now, that does increase the intrinsic value of our acreage, and clearly gives us better well inventory quality. And the fourth thing is the potential for SWD monetization, which I think everyone will agree, will give us additional flexibility in our capital program as we go forward, if indeed this monetization does come to fruition. So thank you very much for your attention, and we'll talk to you next quarter.

[Operator]

This concludes today's conference call. You may now disconnect.