Good morning, and welcome to Centennial Resource Development's Conference Call to discuss its 2nd quarter 2019 earnings. Today's call is being recorded. A replay of the call will be accessible until August 20, 2019, by dialing 855-859-2056 and entering the conference ID number 185,7979 or by visiting Centennial's website at www.cdevinc.com. 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.
Thanks, Lorenz, and thank you all for joining us on the company's Q2 2019 earnings call. Presenting on the call today are Mark Pappa, our Chairman and Chief Executive Officer George Glippus, our Chief Financial Officer and Sean Smith, our Chief Operating Officer. Yesterday, August 5, we filed a Form 8 ks 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 section of our following with the SEC, including our annual report on Form 10 ks for the year ended December 31, 2018. Although we believe the expectations expressed are based on reasonable assumptions, they're 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 Tappler, Chairman and CEO.
Thanks, Hayes. Good morning, and welcome to Centennial's Q2 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.
Thank you, Mark. As you can reference on Slide 14 of the earnings presentation, net oil production for the Q2 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 1,125 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 2nd quarter totaled approximately $214,000,000 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 and A per barrel was down approximately 6% to $1.78 as notional G and A increased marginally compared Q1. LOE per barrel increased 9% quarter to quarter, primarily as a result of higher equipment rental rates, chemical costs and SWD costs. GP and T expense per barrel was essentially flat at 2.34 Q1 to $16.18 per BOE, which was still below our midpoint of guidance. Finally, severance and ad valorem taxes were 7 percent of revenue compared to 7.5 percent in Q1.
Adjusted EBITDAX totaled approximately $170,000,000 for Q2, a 21% rebound for Q1. And GAAP net income attributable to our Class A common stock was $17,900,000 Turning to capital spending. D and C CapEx was approximately $180,000,000 in Q2, a 5% decrease in Q1 despite higher activity levels, particularly on the drilling side. Notably, this marks the 3rd consecutive quarter of declining D and C capital as our drilling and completion efficiencies are translating into lower well costs. Further reductions in per well costs are a significant point of focus for the team.
Facilities, infrastructure and other capital totaled $44,600,000 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, incurred roughly $13,000,000 in land related CapEx during the quarter as we continue to capitalize on attractive opportunities to add high quality acreage at compelling valuations around our existing positions in both Lee and Reeves Counties. Overall, Centennial incurred approximately $237,000,000 of total capital expenditures during the quarter compared to $245,000,000 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 and A guidance by 16% to $2.10 per BOE and GP and T guidance by 12% to $2.65 per BOE. Finally, we are reducing DD and 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 $28,000,000 of cash, 0 borrowings under the revolving credit facility and $900,000,000 of senior unsecured notes.
Based upon the 800,000,000 dollars elected commitment under our $1,200,000,000 borrowing based credit facility, the company had approximately $830,000,000 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 from the prior quarter. With that, I'll turn the call over to Sean Smith to review operations.
Thank you, George. The 2nd 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 by 15% year over year to approximately 27 days during the first half of twenty nineteen. 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 costs continue to trend down year over year as a result of both reduced horsepower cost and per ton proppant 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 1st 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 twenty eighteen. Put simply, we're doing more with less and as a result, we are ahead of plan for the first half of this year.
Just as important, we've been able to drive well costs and cycle times lower without sacrificing well quality. As you can see on Slide 4, we've built upon 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 2nd 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 Third Bone Spring with an approximately 9,800 foot lateral. With a 24 hour IP rate over 4,000 barrels of oil per day, this well achieved an IP30 of over 2,500 barrels of oil per day or 2 60 barrels of oil per day per 1,000 foot of lateral. During its 1st 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 approximate 6,900 foot laterals targeting the 1st, 2nd and third 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 IP30 of approximately 1800 barrels of oil per day or 2 66 barrels of oil per 1,000 foot of lateral and included the 2nd 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-twenty 17. 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 1 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 Third 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 2 Third Bone Spring wells delivered an average IP30 of almost 1900 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 IP30 of approximately 1800 barrels of oil per day or 201 barrels of oil per day per 1,000 third lateral.
The Red Rocks is an important test. First, it represents our first four well test pairing the Wolfcamp Upper A and the Third Bone Spring Sand, proving the viability of multi well co development. Secondly, the production profiles for these wells confirms that the Third Bone Spring Sand will compete for capital with our best rate of return projects. We plan to continue developing the 3rd Bone Spring sand and where possible, co developing 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 would 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-twenty 20, 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 two reasons. Number 1, it means Centennial will continue to be an industry leader in terms of minimizing natural gas flaring. Number 2, 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 Lee and Reeves Counties. As we highlighted on Slide 4, the operations team and all of our employees at Centennial continued to deliver on the goals set forth at the beginning of the year, From well productivity to capital efficiency to G and A per barrel, Centennial continues to operate at a very high level. With that, I'll turn the call back over to Mark. Thanks, Sean. Now I'll provide a few thoughts regarding the oil macro picture and relate 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 1,200,000 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's an equal probability that 2020 oil prices could be $50 or $70 So where does that leave CDEV's strategy?
For the 3rd consecutive year, at midyear, we've raised our volume targets, lowered several of our unit costs and expect to stay within our original CapEx budget range, albeit on the high end this year. That's a 3 year consistent track record few EOP E and Ps can claim. Although we're outspending cash flow, our current debt to cap is only 21%, a level most E and 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 8 80 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 and A. Laurence, want to flag Q and A for us, please?
Thank you. The question and answer session will be conducted electronically. Your first question comes from the line of Scott Hanold from RBC Capital Markets. Your line is open.
Thanks. Good morning.
Mark, I was I'm going to
play out that last comment you made about there's 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?
Yes. Good question, Scott. And I'm just going to have to give you the rather nebulous answer. Flexibility is going to be the watchword. The one advantage we have is there's 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 certainly got all this China noise going on in the 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 position and it will be a function of really what we perceive the oil market to be likely at year end or in January.
Okay. I appreciate that context. And as my follow-up question, maybe for Sean, I don't know, kind of slip in half an extra question here. But with that, two things. 1, 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 the with the better targets that you're looking at? Sort of the question in my extra bonus half question is on that rig you dropped, was there cost associated with that? Or did the contract already roll off?
The second part of that question is easy one. On a contract perspective, we have always talked about rig flexibility and the way we layer in our rigs and rig contracts is that we have the ability to add or drop a rig on a quarterly basis. And so that was just a timing perspective that was the right time to let go of that rig. So there's no penalties associated with that. The contract expired and we decided not to renew it with the point that we are very disciplined on our capital and we want to make sure that we are doing everything in our power to stay within our capital guidance range.
The first part of that question was about well productivity. And I would say that we have not materially changed our completion designs quarter to quarter over year over year. I think we are still doing them in a very similar fashion. There's 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 co development.
And so bringing these wells on simultaneously the more on a co development basis is certainly enhancing our production results as well. And we continue to drill longer laterals as well. So all of those things, I think, are incrementally adding to well performance. Appreciate it. Thanks.
Your next question comes from the line of Irene Haas from Imperial Capital. Your line is
open. Yes. I would like to explore the comment that you made earlier that you'd be spending towards the higher end of the CapEx. Could we have a little color regarding 3rd quarter spending and 4th quarter spending? Would Q3 be kind of flat with 2nd and then with a little decline in 4th with dropping 1 rig?
Yes, Irene, the comments I could give you will really relate to just our general thinking that related in terms of DUCs. We're going to just monitor again the oil price in the history of CDEV, which is only 3 years. We've never created any DUCs. There is a possibility in the Q4, again, depending on the oil price, depending on 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 Q4.
So the Q4 would be the one where we might flex more on our capital budget as opposed to the Q3. And it would be a function of whether we elect to create any deduction 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 one rig essentially for 4 months. I don't know, George or Sean, do you want to give a dollar amount as what they might save for the 4 months?
Sure. I think the impact of that drop rate, Mark, could be anywhere from $30,000,000 to $50,000,000 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 a decline on the facility side of that. And we're essentially going to be flowing more new wells into existing facilities in the second half of the year than we were in the first half of the year, and that's certainly going to benefit the capital profile.
So if that's the case, would you still probably have to you've done a really good job of not tapping your revolver, Would you probably need to do some of that in the second half even with fuel rigs?
Yes. I would expect in the second half of the year, we'll be borrowing under the revolver. We had $28,000,000 of cash and $630,000,000 and it was undrawn, but I think that's a reasonable expectation that we would start to draw in the second half.
Your next question comes from the line of Jade Dawood from Cowen. Your line is open.
Hey, good morning, everyone. It's kind of already hit on in terms of 2020, but was curious, given the efficiencies, if you stay with 5 rigs, throughout the course of 2020, given efficiencies on both the drilling and I guess the completion side in terms of days per day, do you think you could still get off the same number of turner lines in 2020, just given those efficiencies that you highlighted?
I hate to give any projections, Gabe, in the 2020 in terms of how many wells we might drill or complete. I mean, the trend is obviously better than what we projected at the 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, it's 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 that number in January or February. So we're just not going to give any numbers at this stage.
Okay, understood. Thanks, Mark. And then I guess just a follow-up on the development side, the DuPont pilot and the 3 benches of the Bone Spring. Could you just maybe talk about how that kind of fits moving forward into development with the upper zones of the Wolfcamp? Thank you.
Yes. Sean, you want to field that? Sure. Thank you. We're obviously very excited about what went on at the Duck Hunt pad.
So what we wanted to do there was test 3 zones vertically stacked. So all three of those wellbores are essentially right on top of each other. And what we were 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 or 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 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 and I think that's probably what you'll see us mainly focus on in the near term.
Okay, great. Thanks so much for the color, guys.
Yes. 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 8 80 feet. And obviously, with some of the other earnings calls that have come out this quarter, everybody is concerned about spacing. The 8 80 feet would relate to Texas, which we think is the most conservative spacing in the Delaware or Texas of anybody, the New Mexico spacing that we look at, although we don't reference it on that slide, is similarly conservative.
I mean, what are you talking about the Wolfcamp or the Bone Spring, that same 8 80 foot minimum spacing is could be applied there also. Generally, in the Bone Spring, we're looking at 8 80 foot to 1,000 foot spacing. In some cases, it gives up to 13 20 foot spacing. So I would say it's probably not an overstatement to say that the spacing we use in the Delaware, whether it be in Lea County or in Reeves County, is probably the most conservative of any company in the industry. So hopefully that would give some comfort to anybody who chooses to invest in C.
Your next question comes from the line of Neal Dingmann from SunTrust.
Mark, that's for you, George, it's 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.
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 and 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 that 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 many developments, 4 to 6 well developments and it really doesn't have anything to do with the amount of capital committed where you talk about do we want to commit vast amounts of capital before we get any production back. It really is based on a technical efficacy of it. And 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've 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.
Okay. And then just one last, I don't know, I mean, I'm sure you guys have thought about this. I know WPX talked about a buyback given the irrationality of the market and certainly your stock is by far no different here. Given that point, is there anything that such as any sort of near term shareholder return or something different you're considering given how irrational this market is appearing today?
Yes. I mean, we'd love to announce that we're 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 a company that's got the proper leverage ratio given our cash flow outspends to be considering a buyback at this time, Neil.
No, I
think that's right, sir.
Okay. Very good. Thank you so much, Mark.
Your next question comes from the line of Derrick Whitfield from Stifel. Your line is open.
Good morning, all and 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 Northern Delaware?
Yes, Derek. 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 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 3 rigs at Reeves, 2 in Lea County. And we would we're not going to expect results prospectively of wells like the Charizo 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 lee kind of results. And if you project over the next 6 to 9 months, I think we will have some upside surprises, we'll 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 Lee Van Reeves, just due to the rock quality would be my guess.
That's great. And then as my follow-up perhaps for Sean, at a high level, where are you seeing the greatest efficiency gains in your completion operations? And what are your leading edge D and C cost per lateral foot based on the first half efficiencies?
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 your ranch 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 balance of this year.
So I think that's the best I can do on this with that question.
Thanks. It's very helpful. Thanks, sir.
Your next question comes from the line of Will Thompson from Barclays. Your line is open.
Hey, good morning guys. So Mark, maybe to piggyback on some of Neil's question. Clearly, the market has started to the companies that can grow within cash flow and those that can't regardless of balance sheet quality. I'm sure Mark at year 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 the CDEV model was really based on a higher oil price, what's the roadmap 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. I mean, any additional color on that would be helpful.
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 unless you project a more optimistic oil price than the futures market is indicating. I will say that our hard line on debt to cap is 30%. So we're going to have to manage the company within the limitations of that hard line 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,
Mark, that's helpful. And then Mark or Sean, Centennial now plans 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 infrastructure build out in New Mexico. Would you consider small bolt ons?
I know you've been focused on organic inventory growth, but maybe there's opportunity to do continued land trades. Thoughts there would be helpful. Thank you.
Yes. Sean? 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 that that we spend 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 three 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 of 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'll continue to see that going forward. From a small bolt on type of question you asked, we're always looking for opportunities there to add acreage that is adjacent to our positions, whether it's in Texas or New Mexico, so long as they're at competitive prices. And I think you'll see us continue to look for those opportunities going forward.
Your next question comes from the line of Asit Singh from Bank of America Merrill Lynch. Your line is open.
Thanks. Good morning, guys. Mark, I was wondering if I could ask you about your new role as the Chairman of Schlumberger. Historically, in prior patients, you have been an advocate of in house E and P innovation bypassing the service providers. Do you see that model changing?
Is something different in the new world as we deal with issues like parent child? And while you're on that topic, any thoughts on where you see the next big innovation to drive shale growth such as digitization or AI?
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 is limited scope really. I chair the Board meetings 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 service companies and also with the E and P companies to solve that problem, I said.
Okay. Thanks, Mark.
Yes.
Your next question comes from the line of Kashy Harrison from Simmons Energy. Your line is open.
Good morning, everyone, and thank you for taking my questions.
Thanks, Kashy.
So in the prepared remarks, there was some commentary on a 5% reduction in well costs. And in the presentation, you highlight that well performance is tracking 10% above the 2018 levels. And if we take both those 2 things into consideration and then we take what I imagine our lower base declines exiting 2019, I was wondering if you could just help us think through what a maintenance D and C estimate might be to hold the 2019 exit rate flat through 2020?
Yes, Kashy. I mean, we've always shied away from providing numbers on maintenance D and 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 work over rigs and things like that, but it has slightly shadowed 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.
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 was about 17% of the total budget. What's can you kind of help us think through the flexibility in that number?
So for example, 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 to help us think through the evolution of that facility spend depending on what level of activity you're running at any given time.
Yes. George, you want to give some insight on that?
Sure. Thanks, Kashi. 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 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.
Got you. That's it for me. Thank you.
Your next question comes from the line of Kevin McCurdy from Hinkenning Energy. Your line is open.
Good morning, guys. And this is just a follow-up from an earlier question. Mark, given your limited role at Schlumberger, does
lead to any changes in how Centennial is managed?
No, no, Kevin. Not at all. Like I said, I mean, the time I spent at Schlumberger is very de minimis. It doesn't affect anything in the way Centennial is managed. Great.
Thanks for clarifying that and congratulations on the good quarter.
Thank you.
Lorenz, this is Hayes. Do we have any more questions in queue?
No more phone questions at the moment, sir.
Well, great. Well, I just want to say thank you for 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, Lorenz.
You're welcome, sir. Thanks to all our participants for joining us today. We hope you've had this webcast presentation informative.