Permian Resources Corp

NYSE:PR

Earnings Call Transcript 2019-Q2

[Operator]

Good morning, and welcome to Centennial Resource Development's 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 20, 2019, by dialing [phone] and entering the conference ID number 1857979 or by visiting Centennial's website at www.cdevinc.com.

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

[Hays Mabry, executive]

Thanks, Lawrence, and thank you all for joining us on the company's second 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, August 5, 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 risk 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 statement section of our filing 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 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 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'll 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. A 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. As you can reference on Slide 14 of the earnings presentation, net oil production for the second quarter averaged 43,100 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 76,125 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 6-rig program, we spud 23 gross wells in Q2, which was up -- which was 6 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 5 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 1 fewer rig from September onward. 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 we'll 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 $240 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 $48.15 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 $0.81 per Mcf and NGL realizations were $16.24 per barrel.

Shifting to expenses, cash G&A per barrel was down approximately 6% to $1.78 as notional G&A increased marginally compared to Q1. LOE per barrel increased 9% quarter-to-quarter, primarily as a result of higher equipment rental rates, chemical costs and SWD costs. GP&T expense per barrel was essentially flat at $2.34. DD&A expense increased by nearly 9% from Q1 to $16.18 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, a 21% rebound from Q1 and GAAP net income attributable to our Class A common stock was $17.9 million.

Turning to capital spending. D&C CapEx was approximately $180 million in Q2, a 5% decrease from Q1 despite higher activity levels, particularly on the drilling side. Notably, this marks the third consecutive quarter of declining D&C capital as our drilling and completion efficiencies are translating into lower well costs. Further reductions in per well costs are 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 saltwater disposal system.

These are prudent dollars to spend because they provide us significant operating flexibility, maintain lower LOE over time and are very valuable assets in today's 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 Lea 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 41,000 barrels per day, while maintaining our capital guidance range for the year.

Additionally, we are reducing the midpoint of our cash SG&A guidance by 16% to $2.10 per Boe and GP&T guidance by 12% to $2.65 per Boe. Finally, we're reducing DD&A per barrel to a midpoint of $16.25 from $16.50.

On Slide 12, we summarize our capital structure and liquidity position. At June 30, we had approximately $28 million of cash, 0 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-based credit facility, the company had approximately $830 million of liquidity at June 30. Finally, our leverage profile was essentially flat quarter-to-quarter. Centennial's net debt-to-book capitalization at June 30 was 21%, up modestly from 20% at March 31 and net debt to last 12 months EBITDAX of 1.3x

[Audio Gap]

from the prior quarter.

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

[Sean Smith, executive]

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 7, we 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 in 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 downhole assemblies designed to perform optimally based on our evolved understanding of the reservoir characteristics. Similarly, we're completing more stages per day compared to 2018. During the first half of the year, we averaged approximately 6 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 profit cost. Combined, these efforts have resulted in increased capital efficiency as year-to-date well 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 7, 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 6 to 5 rigs in early September, while spudding and completing more wells than previously anticipated under our original 6-rig program. To put this into context, during the first 6 months of last year, we spud and completed 41 and 36 wells, respectively, utilizing a 7-rig program. This year, our 6-rig program spud essentially the same amount of wells, and we've completed an additional 4 wells compared to the first half of 2018.

Put simply, we're doing more with less, and as a result, we're ahead of plan for the first half of this year.

Just as important, we've been able to drive well costs and cycle times lower without sacrificing well quality. As you can see on Slide 4, we've built up on the productivity gains we saw earlier in the year. This graph depicts Centennial's 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 5. In New Mexico, Centennial completed its 2 best producing wells to date. The first well, the Chorizo 601H targeted the 3rd Bone Spring with an approximating 9,800-foot lateral. With a 24 IP -- with a 24-hour IP rate over 4,000 barrels of oil per day, this well achieved an IP-30 of over 2,500 barrels of oil per day or 260 barrels of oil per day per 1,000-foot of lateral.

During its first 60 days online, the Chorizo produced over 110,000 barrels of oil and represents our best well drilled to date. On Slide 6, the 3-well Duck Hunt pad also located in New Mexico was drilled with approximately 6,900-foot laterals targeting the 1st, 2nd and 3rd Bone Spring intervals. These wells were directly stacked with approximately 800 feet of vertical separation between intervals and completed simultaneously for reduced cost and higher efficiency. These wells delivered an average IP-30 of approximately 1,800 barrels of oil per day or 266 barrels of oil per 1,000 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 1 rig on the acreage and essentially all of our results to date have either met or exceeded expectations. Given these results, we expect to shift one of our Texas rigs to New Mexico later this month. At that time, Centennial will operate 2 rigs in Lea County with the remaining rigs located in Reeves County.

Remaining on Slide 6, in Reeves County, the Red Rock's 4-well pad was drilled using a stack staggered pattern targeting the 3rd Bone Spring Sand and Wolfcamp Upper A intervals with approximately 9,500-foot laterals. These wells were spaced approximately 880 to 1,000-feet apart, which is our normal spacing pattern in these intervals. The two 3rd Bone Spring wells delivered an average IP-30 of almost 1,900 barrels of oil per day or 182 barrels of oil per day per 1,000 foot of lateral. The 2 Wolfcamp Upper A wells delivered an average IP-30 of approximately 1,800 barrels of oil per day or 201 barrels of oil per day per 1,000 foot of lateral.

The Red Rock is an important test. First, it represents our first 4-well test pairing the Wolfcamp Upper A and the 3rd Bone Spring Sand proving the viability of multi-well codevelopment. Secondly, the production profiles for these wells confirms that the 3rd Bone Spring Sand will compete for capital with our best rate of return projects. We plan to continue to developing the 3rd Bone Spring Sand and where possible codeveloping this zone with the Wolfcamp Upper A 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 WAHA will continue to trade at or below $0 for the remainder of the second quarter. In fact, WAHA prices averaged negative $0.07 during the quarter, and as you can see in Slide 9. 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 $0.81 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 basin return to being oversupplied in mid-2020 putting pressure once again on WAHA prices. This potential threat is one of the many reasons why our current gas takeaway agreements extend through Q4 2022. This is key for 2 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 4 of the top 5 wells in Centennial's history, and these wells are notable because they targeted 3 separate zones and were equally split between Lea and Reeves Counties. As we highlighted on Slide 4, the operations team and all of our employees at Centennial continue to deliver on the goal set forth at the beginning of the year. From well productivity to capital efficiency to G&A per barrel, Centennial continues to operate at a very high level.

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 old macro picture and relate them to Centennial's strategy. The supply side of the global oil picture is bullish, and it's already apparent to me that 2020 total U.S. oil growth will be considerably less than 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 me, 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 what is at least CDEV's strategy? For the third consecutive year and midyear, we've raised our volume targets, lowered several well unit costs and expect to stay within our original CapEx budget range, albeit, on the high end this year. That's a 3-year consistent track record few E&Ps can claim. Although we're outspending cash flow, I'll note our current debt to cap is only 21%, a level most E&Ps would envy. Also, since this is a current hot topic, you should be aware that our 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're performing as an efficient, well-run Permian mid-cap.

Thanks for listening, and now we'll go to Q&A. Lawrence, I want to flag Q&A for us, please.

[Operator]

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

[Scott Hanold, analyst]

Yes, Mark, I was -- I'm going to play out 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 5 rigs, it looks like, for the course of the rest of this year, how do you plan then for 2020? Like what is the base plan at this point, like how should we think about the cadence of activity to expect from CDEV going into next year?

[Mark Papa, executive]

Yes. Good question, Scott, I'm just going to have to give you a rather nebulous answer. Flexibility is going to be the watchword. The one advantage we have is there is a lot of flexibility available in the rig market. And so we're just going to take advantage of that flexibility. Frankly, we're not sure how many rigs we're going to be running in 2020, and we're going to let the oil market dictate that. The reason I put that comment in about what we think U.S. 2020 year-over-year oil growth is going to be considerably less than what people are currently forecasting is that I still think we could see an upside surprise in the oil market tightening in 2020, and we want to be -- at least have the potential to take advantage of that. On the other hand, you've certainly got all these China noise going on with trade war. So I would say, I mean we could run 5 rigs, we could run as many as 7 rigs in 2020. And we probably will not make that decision until January of 2020 and the rigs are available, we can pick them up on a moment's notice. So we're just going to hang loose and defer that decision and it will be a function of really what we perceive the oil market to be likely at year-end or in January.

[Scott Hanold, analyst]

Okay, and I appreciate that context. And this is my follow-up question. Maybe for, Sean, and I want to kind of slip in half an extra question here, but with that -- 2 things, one, the recent well performance has been very strong, can you talk about -- is there something specific in your completion that's resulting in that? Or is it -- with better targets that you're looking at, sort of the question and my extra bonus half question is on that rig drop, was there a cost associated with that? Or did the contract already roll off?

[Sean Smith, executive]

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 it was just a timing perspective, that was the right time to let go that rig. So there is 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 was about well productivity, and I would say that we had not materially changed our completion designs quarter-to-quarter or year-over-year. I think we're still doing them in a very similar fashion. There is always small things around the edges that we're trying to tweak and do better at. On top of that, we are doing more pad and codevelopment. And so bringing these wells on simultaneously the more -- on a codevelopment 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.

[Operator]

Your next question comes from the line of Irene Haas from Imperial Capital.

[Irene Haas, analyst]

Yes. I would like to explore that the comment that you made earlier that you would be spending towards the higher end of the CapEx and could we have a little color regarding third quarter spending and fourth quarter spending with third quarter be kind of flat with second and then with a little decline in fourth with dropping 1 rig?

[Mark Papa, executive]

Yes, I mean -- the comments I can give you will really relate to just our general thinking and that related in terms of DUCs. We're going to just monitor again the oil price. In history of CDEV, which is only 3 years, we've never created any DUCs. There is a possibility in the fourth quarter, again, depending on the oil price, depending where we stand on our CapEx level, we might create a few DUCs. In other words, we may just elect to drill some wells and not complete them 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 create any DUCs or not. So that's really the key inflection point if we elect to pull the trigger on things. In terms of the number -- the dollar number that we might save or we will save by dropping that 1 rig, essentially for 4 months, George or Sean, do you want to give a dollar amount as what they might save for the 4 months?

[George Glyphis, executive]

Sure. I think the impact of that dropped rig mark could be anywhere from $30 million to $50 million for the year. The other thing -- the other color I'd add to Mark's 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 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 that's certainly going to benefit the capital profile.

[Irene Haas, analyst]

So if that's the case, would you still probably have to -- you've done a really good job of not tapping your revolver, but would you probably need to do some of that in the second half even with fewer rigs?

[George Glyphis, executive]

Yes, I would expect in the second half of the year, we'll be borrowing under the revolver. We had $28 million of cash at 6/30, and it was undrawn. But I think that's a reasonable expectation that we would start to draw in the second half.

[Operator]

Your next question comes from the line of Gabe Daoud from Cowen.

[Gabriel Daoud, analyst]

Kind of heard you hit on in terms of 2020, but was curious -- given the efficiencies if you stay with 5 rigs throughout the course of 2020, given the 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 given those efficiencies that you highlighted?

[Mark Papa, executive]

I hate to give any projections, Gabe, into 2020 in terms of how many wells we might drill or complete. I mean the trend is, obviously, better than what we projected at beginning of this year in terms of days per well per rig. But at this stage, I really don't want to dance around the question, but projections for what we're going to do on production growth or number of wells, we're going to get done in 2020, frankly, it's just too soon to tell. I mean the oil price, as you know, has been all over the map, and 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 to that number in January or February. So we're just not going to give any numbers at this stage.

[Gabriel Daoud, analyst]

And then, I guess, just as a follow-up on the development side. The Duck Hunt pilot and the third -- the 3 branches of the Bone Spring, could you just maybe talk about how that kind of fits moving forward into development with the upper zones at Wolfcamp?

[Mark Papa, executive]

Yes, Sean, do you want to fill that?

[Sean Smith, executive]

Sure. Thank you. We're, obviously, very excited about what went on at the Duck Hunt pad. What we want to do there was test 3 zones, vertically stack, so all 3 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 none 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 -- couple those zones going forward. So it gives us a lot of flexibility in those areas to develop the Bone Spring at whatever pace we elect to going forward. Similarly, if we were to put a Wolfcamp well underneath that, I think, we'd see some similar types of results, although obviously the Wolfcamp out here is kind of a secondary target relative to the Bone Spring. So very excited about Bone Spring results. I think that's probably what you will see us mainly focus on in the near term.

[Mark Papa, executive]

Let me just add one other thing there. We have a note in the IR slides we released yesterday afternoon that our spacing in Texas is -- our basic spacing is 880 feet, and obviously, with some of the other earnings calls that had come out this quarter, everybody is concerned about spacing the 880 feet with relate to Texas, which we think is the most conservative spacing in Delaware or Texas of anybody. The New Mexico spacing that we look at, although we don't reference it on a slide is similarly conservative to what you're talking about the Wolfcamp or the Bone Spring, that same 880-foot minimum spacing is -- could be applied there also generally in Bone Spring, we're looking at 880-foot to 1,000-foot spacing. In some cases, it goes up to 1,320-foot spacing. So I would say, it's probably not an overstatement to say that the spacing we use in a Delaware, whether it would be in Lea County or in Reeves County is probably the most conservative of any company in the industry. So hopefully that will give some comfort to anybody, who chooses to invest in CDEV.

[Operator]

Your next question comes from the line of Neal Dingmann from SunTrust.

[Neal Dingmann, analyst]

Mark, just for you George or Sean. I'm just wondering how do you all think about balancing your optimal size pads with a particular sort of spin -- when you balance that against cash flow during a particular period or looking at your leverage. I'm just wondering how you sort of balance or tie those things together?

[Mark Papa, executive]

Yes, let me take a crack at that. We -- it really goes back to this parent-child issue or the communication issue in the Permian. We started addressing that a couple of years ago, and I think the comments we made a couple of years ago have 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 than on a capital commitment basis.

And I think your question relates to, particularly, these large cube developments that you've seen some of them just haven't worked out too well recently. Our view is we kind of go to mini developments 4- to 6-well developments and it really didn't have anything to do with the amount of capital committed where you talk about -- we want to commit vast amounts of capital before we get any production back, it really is based on the technical efficacy of it. And I would point you to the Red Rock 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 with 4- or 6-well kind of packages and really work the heck out of it technically to minimize the parent-child or communication issues, whatever you want to call it, and go at it that way and that's why we highlighted the Red Rock, particularly, in Reeves County this quarter to show that at least there, we have -- we minimized the interference issues and hopefully that sets a template for us as we go forward. So as we go forward for us, don't expect to hear us highlight of cube-type developments or mega cube developments. Expect us to highlight more of 4-well, 6-well or maybe 8-well kind of multi-zone developments on a go-forward basis, Neal.

[Neal Dingmann, analyst]

Okay. And then just one last one. I don't know -- I mean I'm sure you guys have talked about this. I know even WTX talked about buyback given the irrationality of the market and certainly your stock is by far no different here. Given that point, is there anything that sets us any sort of near-term shareholder return or something different you're considering given how irrational this market is appearing today?

[Mark Papa, executive]

Yes. I mean we loved -- we loved when asked are we considering a buyback. And given the market, that would probably give us some near-term bump in the share price if we just even hinted about a buyback. But frankly, we pay more attention to our leverage ratios, and I just don't think we're the company that's got the proper leverage ratio given our cash flow outspends to be considering a buyback at this time, Neal. It is easy one for us to answer.

[Operator]

Your next question comes from the line of Derrick Whitfield from Stifel.

[Derrick Whitfield, analyst]

Congrats on a strong quarter and update. Perhaps for Mark or Sean, your Northern Delaware well results have been exceptional to date. To what degree could you shift activity from the Southern Delaware to the Northern Delaware?

[Mark Papa, executive]

Yes. Derrick, I mean you're right. We've been very pleased with our Northern Delaware results. They've outperformed any of the pragmatic expectations that we have had in that area. And so we all are implementing pretty much immediately shifting one of our rigs from Reeves to Lea County. So we're going to end up with a ratio on a go-forward basis here essentially of 3 rigs in Reeves and 2 in Lea County. And we would -- we're not going to expect results prospectively of wells like the Chorizo well, which we recently had, that would be too optimistic to program that. But frankly, we expect that we're probably going to continue to beat our type curves with our Lea County results, and if you project over the next 6 to 9 months, I think, we will have some upside surprises will continue and we'll just have a continuous flow of good news, particularly, coming out of Lea County and that's not to denigrate the Reeves results, they're pretty good too. But if I had to just guess, I'm going to guess that we're going to have more headline wells over the next, let's just say, 6 to 9 months coming out of Lea than Reeves just due to the rock quality would be my guess.

[Derrick Whitfield, analyst]

That's great. And then as my follow-up, perhaps for Sean, at a high level, where you have seen the greatest efficiency gains in your completion operations? And what are your leading edge D&C cost per lateral foot based on the first half efficiencies?

[Sean Smith, executive]

So on the completion side, we've done a good job year-over-year. We talked about a 25% increase in number of stages completed year-over-year per day, which is great and a lot of that honestly is kicking over rocks. It's 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 you advantage and just looking for any opportunities to decrease downtime and increase efficiency. So I can't say that it's one thing that all of a sudden we've gone to a certain method that's 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 over time. On the per foot cost, we really haven't released anything along those lines. So I think -- we're certainly doing better, and we've seen a nice decrease in cost year-over-year at least from year-end to current. We're 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 that's the best I can do on this -- with that question.

[Operator]

Your next question comes from the line of Will Thompson from Barclays.

[William Thompson, analyst]

So Mark, maybe to piggyback on some on Neal's question. Clearly, the market has started to bifurcate companies that can grow within cash flow and those that can't regardless of balance sheet quality. I'm sure, Mark, at your old firm, you would have been pretty excited at the prospects of acquiring premium Delaware acreage at Centennial's current dollar per net acre. Given that the CDEV model was really based on a higher oil price, what's the road map in your current thinking to extract value from your acreage? Clearly, you 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.

[Mark Papa, executive]

Yes, Will, yes, it's a tough situation right now to -- since we are in a situation where it's not likely we're going to be even cash flow neutral by 2020 and less -- the less you project the more optimistic oil price than the futures market is indicating. I will say that our hardline on debt-to-cap is 30%. So we're going to have to manage the company within the limitations of that hardline on there. And so what we're going to have to do is just continue the efficiencies that we have, and we originally designed the 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 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 our current strategy. I don't understand why relative to our peers our implied acreage value 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 pretty much everybody else's acreage. And I would argue it's probably better than 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, Will.

[William Thompson, analyst]

It's helpful. And then, Mark or Sean, Centennial now plan to 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 the infrastructure build-out in New Mexico? Would you consider small bolt-ons? I know you've been focused on organic inventory growth or maybe the opportunity to do continued land trades, your thoughts there would be helpful.

[Mark Papa, executive]

Yes. Sean?

[Sean Smith, executive]

Sure. I think it's a fair question. One of the reasons we've been a little bit slower to go towards full scale development in New 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 we're being efficient with the dollars that we spend in both capital and expense wise out there. At this point in time, we've gotten to the position where we feel a lot more comfortable with the infrastructure out there in all 3 of those streams such that we feel confident that having a second rig in New 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 up there certainly warrant additional activity. You mentioned the 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 will continue to see that going forward. From -- small bolt-on type of question that you asked, we're always looking for opportunities there to add acreage that is adjacent to our positions, whether it's in Texas or in New Mexico, so long as they are at competitive prices, and I think you will see us continue to look for those opportunities going forward.

[Operator]

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

[Asit Sen, analyst]

Mark, I was wondering if I could ask you about your new role as a Chairman of Schlumberger. Historically, in prior occasions, you've been an advocate of in-house E&P innovation bypassing the service providers. Do you see that model changing, is something different in the new role as we deal with issues like parent-child? And while you're on that topic, any thoughts on where you see the next big innovation to drive shale growth such as well digitization or AI?

[Mark Papa, executive]

Yes. That question, I mean my role as Chairman of Schlumberger is, I mean, Non-Executive Chairman of Schlumberger. So that's a role that has limited scope really. I chair the Board meetings at Schlumberger is basically my function there. So the issues that exist in the shale development, parent-child issues, interference issues, I think is going to take a lot of technology to fix. 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 E&P companies to solve that problem, Asit.

[Operator]

Your next question comes from the line of Kashy Harrison from Simmons Energy.

[Kashy Harrison, analyst]

So in the prepared remarks, there was some commentary on a 5% reduction in well cost and in the presentation, you highlighted that well performance is tracking 10% above 2018 levels. If we take both of those 2 things into consideration and then we take what I imagine our lower base decline exiting 2019, I was wondering if you could just help us think through what a maintenance D&C estimate might be to hold the 2019 exit rate flat through 2020?

[Mark Papa, executive]

Yes, Kashy. I mean we've always shied away from providing numbers on maintenance D&C. And I think we thrashed through that issue in some of the previous earnings calls there. So all I can point you to is directionally in that -- we've shallowed out our decline a bit. You've seen that come -- this year, you've seen that in terms of our LOE costs relative to last year have actually come up a bit, that's because we're spending more money on workover rigs and things like that, but it has slightly shallowed our decline rate. And 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 that is except directionally things look a bit brighter on that front than they would have 6 months ago.

[Kashy Harrison, analyst]

Got you. That's helpful at least. But -- and then maybe switching gears to my follow-up question. So this year, I think, facilities, infrastructure and other capital is about 17% of the total budget. What's -- can you kind of help us think through the flexibility in that number? So for example, let's just say, you decided to lower activity next year, would we expect that percentage to go down? Or maybe would we expect the absolute number to go down? Just help us think through the evolution of that facility spend depending on what level of activity you're running at any given time?

[Mark Papa, executive]

Yes, George, do you want to give some insight on that?

[George Glyphis, executive]

Sure. Thanks, Kashy. I'd say, on infrastructure, 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 SWD 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, a little bit -- probably a little bit more of a steady pace relative to what we've seen, although as I pointed out in my earlier remarks, the dynamic we're 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.

[Operator]

Your next question comes from the line of Kevin MacCurdy from Heikkinen Energy.

[Kevin MacCurdy, analyst]

This is just a follow-up from an earlier question. Mark, given your limited role at Schlumberger, does that lead to any changes in how Centennial is managed?

[Mark Papa, executive]

No. No, Kevin. Not at all. Like I said, I mean the time I spend at Schlumberger is very de minimis. It doesn't affect anything in the way that Centennial is managed.

[Hays Mabry, executive]

Lawrence, this is Hays. Do we have any more questions in queue?

[Operator]

No more phone questions at the moment, sir.

[Hays Mabry, executive]

Great. Well, I just want to say thank you, everybody, for joining us on today's call. Feel free to call me if you have any questions, and we can end the call now. Thank you very much, Lawrence.

[Operator]

You're welcome, sir. Thanks to all our participants for joining today. We hope you found this webcast presentation informative. This concludes our webcast, and you may now disconnect. Have a good day.