Permian Resources Corp

NYSE:PR

Earnings Call Transcript 2017-Q4

[Operator]

Good morning, and welcome to Centennial Resource Development's conference call to discuss its full year and fourth quarter 2017 earnings. Today's call is being recorded. A replay of the call will be accessible until March 13, 2018 by dialing [phone], and entering the conference ID number, 9488549, or by visiting Centennial's website at www.cdevinc.com.

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

[Hays Mabry, executive]

Thanks, Emily, and thank you all for joining us on the company's fourth quarter and full year 2017 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, February 26, we filed a Form 8-K with an earnings release reporting 2017 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 Statement section of our filings with the Securities and Exchange Commission, including our annual report on Form 10-K for the year ended December 31, 2017 which was also filed with the SEC yesterday. 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 measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website.

And with that, I would like to turn the call over the Mark Papa, Chairman and CEO.

[Mark Papa, executive]

Thanks, Hays. Good morning, and welcome to Centennial's Fourth Quarter 2017 Earnings Call. The presentation sequence on this call will be as follows: George will first discuss our fourth quarter and full year financial results, liquidity and 2018 guidance; Sean will then provide an operational update for the quarter; and then I'll follow with my views regarding the oil macro, our strategy as a function of the macro and closing comments.

Now I'll ask George to review our financial results.

[George Glyphis, executive]

Thank you, Mark. During the fourth quarter, we continued to successfully execute our 6-rig program and completed 26 wells. As you can reference on Page 6 of the earnings presentation, oil production for the fourth quarter increased 30% from Q3 and averaged approximately 27,400 barrels per day. This drove annual oil volume slightly above the high end of our full year guidance. Average oil equivalent production totaled approximately 44,300 barrels per day, a 28% increase compared to the third quarter. Oil volumes as a percentage of total equivalent production were 62%. Going forward, we expect oil as a percent of total production to be approximately 60%, and this number can fluctuate slightly quarter-to-quarter depending on how much capital is allocated to our higher GOR area within Reeves County.

On Page 21, revenues for the fourth quarter were $166 million compared to approximately $112 million in the third quarter. This 48% increase was driven primarily by higher sales volumes and a $52.45 realized oil prices before hedges in Q4 compared to $44.95 in Q3. The last of our legacy oil swaps rolled off at year-end, so we currently have full exposure to oil prices going forward.

Lease operating expenses, including workover cost, totaled approximately $14.4 million for the fourth quarter or $3.54 per BOE. This was essentially flat on a per unit basis compared to Q3 and at the upper end of our annual guidance range, primarily as a result of the higher percentage of our total disposal water being trucked. Gathering, processing and transportation expenses totaled $11.7 million for the quarter or $2.87 per BOE which compares to $3.11 for Q3.

Cash G&A expenses of $2.45 per BOE were 21% lower compared to Q3 as notional cash G&A was flat at approximately $10 million quarter-to-quarter, while production volumes were up significantly. DD&A totaled $58.8 million or $14.42 per BOE compared to $13.28 in the third quarter. This was a 9% increase on a per unit basis relative to Q3, driven primarily by higher D&C cost for the quarter. EBITDAX totaled $120 million, a 62% increase compared to $74 million in Q3, and this was driven by higher production volumes, higher realized oil prices and a solid cost profile. Cash interest cost on a per unit basis increased to $0.81 per barrel from $0.39 in Q3 because of higher borrowings and the issuance of senior unsecured notes in November, which significantly improved our liquidity position.

Net income to common shareholders totaled $30.5 million or $0.12 per diluted share, doubling from $0.06 per diluted share in Q3. Centennial incurred approximately $246 million of total capital expenditures during the quarter, of which approximately $226 million was related to drilling and completions, including facilities, which on a go-forward basis, we will break out in our guidance numbers for greater transparency. The D&C expenditures were higher than we anticipated primarily as a result of a shift of drilling more extended laterals. We drilled more extended laterals in Q4 compared to the previous 3 quarters combined, and our initial extended lateral D&C estimates per well were simply too conservative. Additionally, we had a higher working interest in Q4 than originally forecast as a result of some good work by Centennial's land team. And finally, some costs from previously drilled wells carried over into Q4.

Our fourth quarter closed out a very successful 2017. Centennial's production exceeded the high end of our annual guidance range, which was a solid result given that we've increased production guidance on 3 separate occasions during the course of the year. Per unit cost generally came as expected after having lowered unit cost guidance midyear, and D&C cost, as noted, were higher than we anticipated primarily because of greater costs associated with extended lateral activity. That said, we will continue to shift our activity towards extended laterals as they generate significantly stronger returns in single-section wells. In fact, we expect our 2018 average completed lateral length to increase approximately 30% year-over-year to approximately 7,500 feet. Our accomplishments during this year built a solid foundation for our 2018 development program and beyond.

Turning to Page 18 of the presentation, you can reference Centennial's balance sheet items and liquidity position. In November, we accessed the capital markets with a $400 million offering of senior unsecured notes at a coupon of 5.375% and a January 2026 maturity. Proceeds from the offerings were used to repay -- fully repay borrowings under our revolving credit facility and to pre-fund a portion of our 2018 development program. At December 31, we had approximately $117 million of cash and $400 million of debt, with nothing drawn on the revolver. Concurrent with the bond offering, we voluntarily reduced the amount of our borrowing base from $575 million to $475 million. As a result, at year-end, we had approximately $590 million of liquidity, which includes cash plus $474 million of availability under the credit facility. Centennial's net debt to book capitalization stood at 8%, and net debt to Q4 annualized EBITDAX was 0.6x. We will continue to prioritize low leverage levels and significant financial flexibility going forward.

Turning to 2018 guidance which is summarized on Page 20. The midpoint of our oil production guidance is 35,500 barrels per day. That represents an 85% growth rate from 2017 to 2018. Importantly, we are revising our 2020 oil production target from 60,000 to 65,000 barrels per day. This increase is primarily a function of more prolific expected well performance as it does not constitute a change to our previously anticipated rig cadence. We added the seventh rig in February, and expect to remain at 7 rigs throughout the course of 2018. The midpoint guidance for our total capital budget is approximately $970 million, of which $765 million is related to D&C CapEx. Approximately $690 million is tied to operated D&C cost, with an additional $100 million budgeted for well-level facilities and infrastructure which primarily includes the construction of pads and tank batteries. With our operated D&C budget, we expect to drill 80 to 95 gross wells and complete 75 to 85 gross wells during 2018. Nonoperated D&C CapEx is estimated at $75 million or approximately 10% of our total D&C budget. We've also allocated approximately $35 million for infrastructure spending. This is primarily related to the build-out and enhancement of our SWD facilities, including the construction of additional saltwater disposal wells, injection upgrades on our existing SWD wells and a water pipeline. This CapEx will benefit Centennial over time as these enhancements will continue to minimize the utilization of trucking services for saltwater disposal. Lastly, seismic and other CapEx is estimated to be $7.5 million.

Turning to unit costs, lease operating expense is estimated at $3.60 to $4.20 per BOE. This guidance range which is higher than our 2017 actuals, reflects higher anticipated water handling cost and some general cost inflation. GP&T is expected to be $3.20 to $3.80 per BOE during 2018. This increase from 2017 levels is almost entirely associated with firm transportations and other arrangements for our residue gas. As a result of recent and projected drilling activity in the Delaware Basin, we believe that securing occurring natural gas pipeline capacity out of Reeves County will become more challenging as the year goes by. Therefore, over the past year, we entered into several transportation services agreements for essentially all of our expected gross natural gas production in 2018 in order to ensure delivery to market. Centennial has agreements or extensions in place after 2018 and we'll monitor future needs on an ongoing basis. Cash G&As per BOE is estimated at $2.20 to $2.70 per barrel, as production volumes and measured notional G&A growth continue to drive unit cost down. Noncash stock-based compensation is estimated at $0.90 to $1.20 per BOE. DD&A is estimated at 14% to 16% per BOE to reflect slightly higher F&D costs and severance and ad valorem taxes are estimated at 6 to 8% of revenue. Finally, we're fully unhedged on a fixed-price oil and natural gas production basis. We have entered into some basis hedges for both oil and natural gas, but as a reminder, natural gas revenue represented less than 10% of total sales during the fourth quarter, therefore we have relatively minor financial exposure to basis differentials at WAHA.

And before I turn the call over to Sean, on behalf of Mark and the entire management team, I'd like to welcome Matt Hyde as our newest independent board member which became effective in January. Most recently, Matt served on the executive management team of Concho Resources as Senior Vice President of exploration. Prior to his 8-year tenure at Concho, Matt spent over 25 years in Occidental Petroleum in various international and domestic roles, including asset manager of Oxy Permian. His public company experience, technical acumen, and vast knowledge of the Permian Basin will greatly benefit Centennial's future growth.

And with that, I will turn the call over to Sean Smith to review operations. Sean?

[Sean Smith, executive]

Thank you, George. The fourth quarter represented another solid quarter of solid execution for Centennial. We brought strong well results online for both the Northern and Southern Delaware Basins, including an Avalon test, 2 successful Bone Spring delineation tests and a positive down-spacing test in the Wolfcamp A. During the quarter, Centennial operated 6 rigs, which spud 18 wells and completed 26 wells. Even in light of the current tightness in the overall oilfield service market in the Permian Basin, we were able to complete 721 stages which is more than double the number of stages completed in the third quarter. More importantly, we were able to accomplish this while also increasing our overall well productivity.

Turning to our well results on Slide 7. We recently completed the Weaver C T34H, targeting the 3rd Bone Spring Sand in Reeves County. We're excited about the Weaver, which represents our first 3rd Bone Spring Sand completion using enhanced completion techniques. The Weaver was drilled within an approximately 9,400-foot lateral, and was producing over 2,000 barrels of oil equivalent per day or approximately 1,500 barrels per day during its 10th day online. Based on its initial flowback, which remained strong, the Weaver appears to be similar to our Wolfcamp A with regards to productivity. This is encouraging as we believe the 3rd Bone Spring Sand could be codeveloped with the Wolfcamp A across a significant portion of our Reeves County position. During the remainder of the year, we expect to complete several additional tests in this zone.

During the fourth quarter, Centennial also bought online the Big House C 3H in the 3rd Bone Spring Carbonate interval. Located on the company's Miramar acreage, the Big House was drilled with a short lateral of approximately 4,000 feet and reported an IP30 of 800 barrels of oil equivalent per day, consisting of 60% oil or 120 barrels of oil per 1,000-foot of lateral. Notably, we estimate that by adjusting the Big House for an extended lateral, it would generate approximately a 45% pretax IRR in today's commodity price environment. Therefore, we plan to continue testing this zone and we'll drill an additional long lateral well during the year.

In addition to the Bone Spring, Centennial continues to deliver impressive results through its Wolfcamp development across its entire position in Reeves County. Targeting the upper Wolfcamp A, the Blackstone West 1H and 2H were drilled with an approximately 4,100-foot lateral length, and produced average IP30s of over 1,500 barrels of oil equivalent per day, consisting of roughly 80% oil. On a per lateral-foot basis, these wells delivered IP30s of 342 and 263 barrels of oil equivalent per day, respectively.

Located on the southern portion of our Reeves County acreage in the Big Chief area, the Sundown 1H well was drilled with an effective lateral length of 4,150 feet in the Wolfcamp Lower A. This well achieved an IP30 of approximately 1,250 barrels of oil equivalent per day, consisting of 88% oil. On a per 1,000-foot of lateral basis, this equates to 268 barrels per day.

Lastly in Reeves County, Centennial also reported an impressive initial down spacing test with the Big House A 4 57-60 1H and 2H. These wells were drilled at 660-foot spacing, implying 8 wells per section per zone. With approximately 7,000-foot laterals, the Big House 1H and 2H both generated IP30s of approximately 2,705 barrels of oil equivalent per day and 2,730 barrels of oil equivalent per day, respectively, consisting of over 50% oil. Additionally, these wells achieved approximately 200 barrels per day and 206 barrels per day on a per 1,000-foot basis, and the 2-well pad had accumulated production of over 137,000 barrels of oil during its first 60 days online. As a reminder, essentially all of our current inventory is predicated on 880-foot well spacing. While early, this positive down spacing test could prove additional inventory on our acreage. Centennial plans to perform additional spacing test during 2018.

Now shifting to the Northern Delaware Basin, Centennial commenced an operating drilling program during September of last year and the initial results are positive. Our first operated well was the Pirate State 101H, which targeted the Avalon shale and had an effective lateral length of approximately 4,200 feet. This well achieved an IP30 of approximately 1,100 barrels of oil equivalent per day, with a 79% oil cut. During its first 60 days online, the Pirate State produced approximately 49,000 barrels of oil. The Tour Bus 23 State 503H and 504H represented 2 well pads drilled in the second Bone Spring. These wells averaged approximately 4,000 feet of lateral length and reported an IP30 of just over 1,000 barrels of oil equivalent per day per well. On a per lateral foot basis, these wells averaged 210 barrels per day per 1,000 feet of lateral during the initial 30 days of production. We expect to continue to operate 1 rig in the Mexico throughout 2018 and look forward to completing wells in additional proven zones throughout this acreage position. Furthermore, these solid initial results support our confidence in the Lea County asset, and underpin our decision to expand our position through the One Energy acquisition.

Shifting to Slide 14. Centennial also delivered strong reserve growth during 2017. Total proved reserved -- reserves increased 125% to 186 million BOE at year-end 2017. Due to the combination of increased well performance and activity, we organically replaced over 950% of our 2017 production at an attractive drill bid F&D cost of $5.47 per BOE. Year-over-year, our proved reserve value on a PB10 basis increased more than 300% to approximately $1.7 billion. As many of you saw in our earnings release, we announced the bolt-on acquisition of approximately 4,000 net acres in Lea County for $95 million from One Energy as seen on Slide 15. Largely contiguous to our existing acreage, this acquisition increases our Northern Delaware position by roughly 30% to over 16,000 net acres. The acquisition represents an operated position with a high working interest of 95%. Additionally, we estimate the acquisition will add approximately 100 gross location to our inventory in the Northern Delaware Basin. Furthermore, this contiguous bolt-on enables the conversion of 20 existing short laterals on the GMT acreage to become extended laterals, significantly increasing the potential Wellhead IRRs. As you've heard Mark say before, we will only add acreage if it meets all 3 of our acquisition parameters: one, the inventory must be as good or better than our current portfolio; two, the prospective acquisition must be accretive to our financial and operating metrics; and three, it must be consummated at an attractive price as we will not overpay for acreage. We believe that One Energy acquisition meets all 3 of these criteria and are excited to integrate this acquisition. The transaction closed on February 8 of this year. In addition to the acquisition, we also announced plans to divest 8,600 net acres in Reeves County for approximately $140 million. As you can see on the slide, this acreage is located on the western portion of our position in Reeves County. The divestiture is largely nonoperated and had a minimal current production, hence the reason we were willing to part ways with it. Due to the nature of these assets, the divestiture does not impact our production target or inventory. The divestiture is expected to close on March 1, 2018, subject to customary closing terms and conditions.

Combined, these transactions represent an upgrade to our overall acreage quality as we are essentially swapping out nonoperated low working interest properties in Reeves County for a proven, high-quality operated position adjacent to our existing position in Lea County.

[Mark Papa, executive]

Thanks, Sean. Now I'll provide some thoughts regarding the oil macro picture and relate them to Centennial strategy. Since Centennial is just slightly over 1-year-old as a fully functioning company, I'll also provide some perspective regarding how we made it up to our first year goals and what we expect to accomplish in our 2nd year. Oil prices have recently responded to the global inventory drawdown caused by tightening supply/demand fundamentals, and the focus now turns to 2018 U.S. oil supply growth. Many forecasting agencies are predicting U.S. oil growth of between 1.4 million and 2 million barrels per day this year. As I previously noted, I expect actual U.S. growth will be less than many forecasters are currently predicting which will support 2019 and future oil prices. Centennial's response to the global supply/demand picture is as follows: We will continue to remain unhedged regarding oil. Additionally, we've increased our 2020 production targets from 60,000 to 65,000 barrels per day based on our strong well results. We expect to accomplish this without increasing our rig count or capital commitment from our previous plan. And I'll also ask you to focus on 5 slides in our IR presentation we released last night. Slide 5 outlines the 9 2017 company goals we articulated in March of 2017. You'll note that we met or exceeded each of these goals during 2017, which is pretty significant considering these were not all easy goals. During 2017, we raised our oil volume estimates 3x, established our sales as a mid-cap technical leader in well completion technology, commercially tested 2 Bones Springs [ productive minerals ], and improved our acreage quality with several transactions. Slides 11 and 12 compare our well results on a bbl/ft basis with other operators in the southern Delaware. I'm particularly pleased that in 1 year's time, we've accomplished this high comparative level of technical efficiency. Slide 7 outlines our Bone Spring Sand results which is particularly notable. Without performing an expensive M&A, we've added 100% IRR inventory, that's [Audio Gap]. With this new zone, we've increased our drilling inventory with essentially no incremental capital cost. I know there's a lot of discussion going on now about capital efficiency and a lot of discussion going on relating to 2018 CapEx levels compared to analyst estimates, but the true point about capital efficiency really relates to this Bone Spring zone. The key point here is that we've added a significant amount of high IRR inventory at no incremental cost, and that's the key to improving capital efficiency. Slide 19 provides our 2018 goals. The point I'd make here is that we strive for consistency as a company. Simply put, we deliver on our promises. We have the highest net adjusted 2017 through 2020 oil compound annual growth rate in the industry in a positive oil price environment, and we expect to generate reasonable GAAP ROEs and ROCEs this year. Thanks for listening. And now, we'll go to Q&A.

[Operator]

[Operator Instructions] Your first question comes from the line of Irene Haas from Imperial Capital.

[Irene Haas, analyst]

My question has to deal with 3rd Bone Spring carbonate. Understanding it's early, do you have a feeling as to how extensive this particular target is over your acreage in Reeves County?

[Mark Papa, executive]

Yes, Irene. Yes, the 3rd Bone Springs carbonate, I would say is -- based on what we know today, is extensive, roughly, maybe 2/3 of our acreage and what I would tell you about that play is: number one, I don't want to oversell it right now. I'd say, in baseball parlance, the first well is what I'd say a single or a double, it's not a home run. As we pointed out in the slide in our IRR presentation, the first well really doesn't meet the economic threshold that's competitive with the rest of our portfolio. It was a short lateral. Modeling indicates it as a long lateral, 2-mile lateral, we would have economics that would compete with the rest of our portfolio. So our plans are likely in the fourth quarter this year, we will drill a 2-mile lateral, and we're probably going to move the target a bit, probably maybe a little bit lower in the section, in this carbonate section, and see if we can improve the productivity a little bit by doing that also. And so by year-end, we'll have 1 other test here and see whether this really is, again, something that's going to fit in our portfolio for 2019 and forward. At this juncture, I'd say that we're very optimistic about the 3rd Bone Spring Sand, and we would just identify the 3rd Bone Spring Carbonate as a potential additional Bone Spring target.

[Operator]

Your next question comes from the line of Scott Hanold from RBC Capital Markets.

[Scott Hanold, analyst]

First, maybe if I could just add on to the thought that you just finished. As you look at your 2018 program, it looks like, it could be very heavily weighted to the Wolfcamp A, and just the upper A -- and just as a question in terms of if you do get success in the 3rd Bone Spring Sand and you plan to codevelop that going forward, would that be incremental activity? Or would you just shift a little bit more Wolfcamp A to a Bone Spring?

[Mark Papa, executive]

Yes, Scott. Excellent question. The -- it looks like right now that preliminary thought would be that we probably are setting ourselves up here for kind of parent-child drilling for the 3rd Bone Sand in the Upper Wolfcamp A. If we had to make -- guess, ride or die at this 10 section -- seconds. So you're correct in that our program as we would define it right now is heavily weighted toward upper Wolfcamp A for 2018, but we're going to drill a confirmation well in this 3rd Bone Spring Sand sometime pretty quickly because of our really good result from the Lea well. And if that confirmation well turns out like we expect it to, then we will probably alter our program for the second half of this year, and net-net we'll drill less Upper A wells than we would've initially expected and more 3rd Bone Sand Wells. So we're not going to increase the number of wells relative to the estimate that we provided last night, but the mix of those wells could change such that there will be more 3rd Bone Sand wells and less Upper A wells and that will likely be skewed and occur in the second half of the year. That's my best guess at this 10 seconds as to what is likely to occur in 2018.

[Scott Hanold, analyst]

Okay. Are those well costs pretty comparable between the 2 zones?

[Mark Papa, executive]

Yes. I mean, the 3rd Bone is just slightly shallower but not that much. So for the horseshoes and hand grenades, yes, you can just say the well costs are comparable.

[Scott Hanold, analyst]

Okay, no, fair enough. And just a question on the CapEx for '18, there is a decent-sized number that is infrastructure spend. And could you give us a little context around that? Is some of the infrastructure spend that you'll be doing this year benefits, I guess, wells down the road? Or should we assume, on a go-forward basis, there is that amount to be associated with the relative well count?

[Mark Papa, executive]

Yes. Sean, do you want to field that question?

[Sean Smith, executive]

Sure. It's a good one. I think that you can think of that infrastructure spend in kind of 2 buckets, but the majority of which is a recurring cost so while we will have some reduction in capital, because there will be some shared infrastructure and wells down the road as we continue to build out this field, majority of these costs are associated with bringing individual wells online. So I think it's a decent number kind of going forward on a percentage basis although there will be some reductions in later years.

[Scott Hanold, analyst]

Okay. Got it, got it. And then when you -- on your presentation, I think, on page 20, you showed those target ranges and that encompasses some of that infrastructure spend on those average well costs, is that, right?

[Sean Smith, executive]

Yes.

[Operator]

Your next question comes from the line of Subash Chandra from Guggenheim.

[Subash Chandra, analyst]

Question first, I guess, on just the free cash flow outlook with some of the CapEx updates and production updates. Do you have a revised view as to when you might be targeting neutrality or free cash flow and maybe timing or conditions? Price required, et cetera?

[Mark Papa, executive]

Yes, Subash. Again, our view is we -- again, we're a little bit unusual company in that, we started out with essentially 0 debt. So as you know, our current net debt is about 6%. So we're -- we are outspending cash flow quite obviously in 2018. We would likely outspend our cash flow in 2019. Based on our model, 2019, we should achieve neutrality, and that's based on roughly a $65 WTI price in there. And so we get the question a lot with, gee whiz, your outspending cash flow, that's bad. Our mode is we designed this company to come out in our genesis with 0 net debt because we knew we had to reach a certain critical mass to be a meaningful company, and I'd define a critical mass as 60,000 to 65,000 barrels per day and by our modeling calculations, we never exceed a net debt to total cap of roughly 20%. And so I find it a little bit strange that sometimes we get questioned about, you're outspending cash flow when we're one of the lowest net debt companies and projected to be one of lowest net debt companies even through 2019 and 2020. But yes, we should reach neutrality by 2019 or 2020.

[Subash Chandra, analyst]

Okay, great. And I guess, repeat Irene's question she asked on the carbonate to the Bone Spring Sands, how extensive a blanket that you might think it is versus how channelized it might be across Reeves County?

[Mark Papa, executive]

Yes. On the Bone Spring Sand, the -- that looks to be covering probably roughly 3/4 of our Reeves County acreage, in a very rough number. The question, and again, we have offset operators, I think certainly Noble and, I believe, Concho have also had some pretty good 3rd Bone Spring Sand results recently so it's a zone that is pervasive, not just on our acreage, but on an acreage kind of around our area too. The question on the 3rd Bone Spring Sand is, it is more of a quartz type elements to it, obviously, when we use the word sand than shale. So the question that comes in, is what is the spacing you would get for a 640-acre unit? How many wells could you put in the 640-acre unit? Is it 4 wells? Is it 6 wells? So on and so forth. So we're going to have to do some work on that. But I would say that this is a pretty meaningful result, this 3rd Bone Spring Sand result. This is not a one-off deal. This looks like something that is going to turn out to be a pretty significant development on our acreage and, as we noted, the pro-well IRRs looked quite attractive, so we're pretty excited about this result. The carbonate, just on to touch on the carbonate for a minute, nobody, to our knowledge, nobody has really tested this 3rd Bone's carbonate in the area maybe for a 40- or 50-mile radius around our well. So the carbonate is really a, I call it, kind of a semi-wildcat. So this is a true original test, if you will. So it is meaningful in that we've got a well that is probably going to be commercial on a 2-mile lateral basis, but nobody has tested for quite a large area. So we just have to see how that plays out and so it's pretty neat that we do have that established also.

[Subash Chandra, analyst]

Just final pair of questions. So spacing could be different in the sand as you said. Do you think the decline rate would look any different than the Wolfcamp? And the second question is, is the Wolfcamp sands, with all these intervals, Wolfcamp sands still a target, a viable zone that you may want to sequence somewhere between the Bone Spring and the Wolfcamp this year?

[Mark Papa, executive]

The Wolfcamp Sands or the Wolfcamp Shales or silts, if you will? Are you talking about...

[Subash Chandra, analyst]

Yes. I was thinking about it's probably closer the northern part of Texas, but the [ X-Ys ], and if it gets down to your acreage?

[Mark Papa, executive]

The X-Y doesn't really exist on our acreage. So that's likely not a target on our acreage. So...

[Subash Chandra, analyst]

Got you.

[Mark Papa, executive]

That's not one we're going to be targeting, really. There are a couple of other Bone Spring intervals that are a potential on our acreage, and of course, we've got Wolfcamp B and C there, that are paying on our acreage. But I guess, in terms of new zones, we may test another 1 or 2 Bone Spring intervals that could pop up that may potentially be pay intervals.

[Subash Chandra, analyst]

Did you think the decline rate is similar to the shale?

[Mark Papa, executive]

Yes, yes. We've got some production history on some of this 3rd Bone Sand. And yes, I'd say again, horseshoes and hand grenades, yes. Fairly similar.

[Operator]

Your next question comes from the line of Michael Glick from JPMorgan.

[Michael Glick, analyst]

You all talked about signing up some ST. How do you think about -- how do you see things playing out on the gas side in the Del from a macro perspective? And maybe or when do you think things could go sideways in the basin in terms of getting gas out?

[Mark Papa, executive]

Yes, Michael, good questions. Yes, I mean, everybody knows that Apache is proceeding developing their Alpine High area, and that's obviously going to move -- put a lot of gas into that WAHA hub, which is going to be pretty much a very gassy play, that Alpine High will be. And then you've got certainly a lot of the casinghead gas coming from the oil development in Reeves County. So we have some concerns for 2018, 2019, 2020, for that timeframe that you could have some issues on: number, getting our gas to WAHA; and then number two, getting our gas away from WAHA. And so the increase that you've seen in our GP&P estimates for 2018 is we have taken out some transportation commitments to kind of make sure that, at least for 2018 and for parts of 2019, that we've got firm transportation there. And we're working on doing some additional things for 2019 in there. So I would say, out of all the, kind of take away issues in Reeves County, you've got -- can you get your oil moved off lease? Can you get your NGLs moved off lease? And then can you get your gas moved off lease? We feel very comfortable on the oil question, on the NGL question. The one we have some degree of concern about is the gas question, and where you kind of put us right now is 2018, we have very comfortable. 2019, we are somewhat comfortable, but we still have some work to do on 2019 and probably 2020. We think post-2020, there'll be additional infrastructure in place where it's probably not going to be a problem. So that's kind of the macro view, Michael, as we'd see it. And of course the other issue you have, and as we noticed on some other Permian, but particularly Delaware players [ on these calls ], is water disposal -- produced water disposal. That could trip you up also because for every barrel of oil you produce, you produce a significant amount of water also. Can you really get your produced water disposed of properly? And you're seeing that our LOE has moved up a little bit because of the water disposal cost. We feel, say, reasonably good that we've got our water disposal issues pretty well in hand, but it's something that we just have to just continually focus on to make sure that somewhere a year or 2 down the road, we don't have to shed any oil because we can't get rid of the produced water. Does that give you kind of a macro view?

[Michael Glick, analyst]

Yes. I mean, do you see the potential for shut-ins and flaring in the Del over the next couple of years?

[Mark Papa, executive]

Yes. I mean, I see that on a -- the potential that some producers could have to deal with that, yes, and our goal is that we're not one of those producers.

[Michael Glick, analyst]

Got you, got you. And then just more on the productivity side, I mean, obviously it continues to trend up and to the right. Can you talk about the latest and greatest on lateral placement and completion side that's driving these continued gains?

[Mark Papa, executive]

Yes. I've kind of got 2 answers on that: one is on the frac technology side, I think that we've now reached the point where we're getting our laterals in zone, like 96% of the laterals where it's supposed to be generally, and we're now up to between 2,500 and 3,000 pounds of proppant per foot, and we're 100% slickwater. So I think what we have done a lot over the last year to get our frac technology and our completion technology to state-of-the-art, and that is showing in our relative well results that we've got several slides in our presentation compared to other companies. But I'm just not convinced that over the next 2 or 3 years, you're going to see continued improvements of 10% or 15% per year, per year, per year, in per well productivity or per foot productivity because I'm not sure where we go next and frac technology or completion technology to get us those improvements. And that's one reason why I kind of think on a macro scale where the U.S. oil production may disappoint a lot of those optimistic forecasters as to what rate of growth we're going to see from [ total year's ] oil production.

[Michael Glick, analyst]

Got it. And then, I guess, my last question, how do you feel about your overall position as it stands today? And just given that you traded at a premium to the group, do you have any thoughts or appetite for corporate M&A?

[Mark Papa, executive]

I feel very good about our position and I think these 2 land transactions that we outlined today are -- they're relatively small, but I think they did improve our position, get us more out of nonoperated and into operated. At this juncture, don't look for us to be making an M&A -- a big M&A transaction. So right now, I'm more excited about developing this 3rd Bone Spring Sand, putting that in our inventory and getting us to 65,000, and then beyond that, post-2020, then, say I'd like to double the size of the company with some big M&A transformation. So, at this juncture, I would say it's not particularly likely that we're going to do some big transformative M&A.

[Operator]

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

[Asit Sen, analyst]

So, Mark, you -- CDEV has already linked employee compensation to return of capital, and I'm just wondering if you could elaborate how it works down the chain? And I just wanted to get your updated thoughts on outspend versus return on capital shareholder debate, and your thoughts on value creation for an E&P?

[Mark Papa, executive]

Yes, Asit. We've got the employee bonus program, which covers everybody from the CEO down to our lease operators in the field, is really linked to the return of the capital program where we take all capital costs, including land and all those indirect costs, not just direct drilling costs and at the end of the year, we do what kind of IRR did we get of the entire capital program? And if we got a good IRR, then a bonus is higher than if we got a poor IRR. So it does make anybody in the company, like I say, down to the lease operators, focused on if you spend too much money in the capital program, everybody's bonus in the company is going to be lower than otherwise. So there is a linkage. This is the same program I put in place at EOG, so it's a clone of at least a program existed when I was with EOG. In terms of how to create a company that is really focused on value, again, I'm not a big believer in corporate M&A. I go by the theory that most corporate M&As are value-destructive. I really believe in kind of tactical deals. Organic things are much more attractive to me, and that's why I try to make a point on this call that this 3rd Bone Spring Sand is just the kind of thing that I think is really value-creating, because it's essentially free inventory, if you will. I mean it's already on our acreage and now we've added it to our inventory. So those are the kind of things that I'd really like to do as opposed to try and make a really big company. I don't want to become the biggest in the Delaware Basin, I just want to be the most efficient. I'm really big on just technical efficiency because I think that allows you to get the best IRR in our capital programs. So that's why we have so many slides in our IRR presentation about the -- what's our well quality compared to others, because I think that really ties into technical efficiency. And the capital outspend does not bother me at all for 2018 and 2019 because again, because we designed the company with -- to come out of the box with no debt. So what does have my attention is the absolute level of debt and the net debt to total cap ratio and I have a max amount of kind of 25% net debt to total cap, anything north of that starts to scare me. So as long as we stay below that level, I feel pretty comfortable. So those are just some guidelines, [ as I see it ].

[Asit Sen, analyst]

Very helpful, Mark. And then a quick one for Sean. Sean, on the oil cut on the Weaver well, did I hear you say 75%? And then on what extent are you planning to use in-basin sand in 2018?

[Sean Smith, executive]

On the in-basin sand comment, we plan on coming up approximately 50% of our wells using in-basin proppant. That's kind of what we've been doing at the tail-end of 2017 and look to do that in 2018 as well. In regards to the oil cut, it is a 75% oil in the Weaver.

[Operator]

Your next question comes from the line of Mike Kelly from Seaport Global.

[Michael Kelly, analyst]

So well interference issues stemming from either parent-child relationships or too tight of spacing has become pretty topical in this earnings period, and Mark and Sean, I just would love to get your thoughts on how you assess these risks for either CDEV or the industry as a whole and how you plan to kind of mitigate these risks as you move into full field development?

[Mark Papa, executive]

Yes, good question, Mike. Yes, we're currently doing a survey in our whole inventory, and probably, by the third quarter, we're going to have a pretty good assessment of our entire inventory as to what do we think is the proper spacing, whether it's 8 80 or 6 60? As you know, our inventory that we had promulgated about a year ago was all based on 8 80s. We've done some 6 60 spacing tests. We're currently doing a lot tests right now, particularly on the upper A and lower A, parent-child issues there to see what is -- are there parent-child issues or not? And then, with this 3rd Bone Sand, if we do a 3rd Bone Sand and in upper A, the question comes up, would there be parent-child issues with those 2 if we do those together? So in answer to your question, I would say that across the industry, I believe parent-child issues are real, certainly in the Midland and the Delaware Basin is where it's most similar, because you've got these stack pays. They are real. I have always believed and we're seeing it clearly in Eagle Ford now, even with some of the earnings results that have just come out in the last several days that a lot of companies have promulgated their well spacing much too tightly and we're seeing a lot of well interference there. And I predict you will see more of that over the next year or 2 that companies are going to have to say, gee whiz, I thought my spacing could be this tight, but now after drilling some wells I'm going to have to say my spacing has to be a lot more wide than what I had previously said. So I think this is a real issue and all I can say is we're studying it at Centennial. I'm just very glad that when we promulgated our first set of kind of inventory lists, we came out with an 8 80 spacing, which I think is very conservative spacing for the Wolfcamp. So that's just a generalized statement.

[Michael Kelly, analyst]

That's helpful. Just switching topics a little bit. We talked a lot on this call already about the 3rd Bone carbonate and Sands. But we've also asserted here that Felix and some other operators are having some pretty nice success with the 3rd Bone Spring Shale, on kind of the Eastern Delaware front. And I guess I want to confirm that this is actually something different than the 3rd Bone carbonate that you guys tested, and if you see this formation and potential across your acreage and if you plan to test it?

[Mark Papa, executive]

Yes. I confirm that this is different than the 3rd Bone Shale. The 3rd Bone -- and this is different than the 3rd Bone carbonate. There is a 3rd Bone Shale, different than the 3rd Bone carbonate. We have a 3rd Bone Shale potential target on your acreage, and that may be a zone that we may test perhaps later this year, or perhaps early in 2019. So yes, there are several kind of packages like that in this 3rd Bone section. And so I'm gratified to hear that some people are making the 3rd Bone Shale work because that will give us more confidence that we might test it on our acreage.

[Operator]

The last question.

[Mark Papa, executive]

[ One ] more.

[Operator]

I'm sorry, sir, we have a last question coming from the line of Jeanine Wai from Citigroup.

[Chan Wai, analyst]

In terms of the new 2020 oil production target, you discussed a part of it is related to Centennial's response to your oil price forecast. And not to beat a dead horse here, but can you talk about your thought process on increasing the target versus maybe keeping the old target, hitting it on a lower CapEx and then potentially narrowing the outspend a little bit faster? And I'm just trying to square your comments with the fact that 60,000 to 65,000 a day is already critical mass, and kind of what do you do after that?

[Mark Papa, executive]

Yes, Jeanine, number one, I mean, if -- I've always said that you can contradict what our 2018 and 2019 oil production target was by just kind of taking a straight line to 60,000 barrels per day. But if you really have been following our targets, that straight line was really pointing to 65,000 in any case. And so for those of you that were the analysts, I think most of you were kind of saying, heck, they're on a blind path to 65,000 barrels per day in 2020 anyway, so the fact that we've now kind of fessed up that the target 65,000 instead of 20,000, is I think, just a confirmation of where our straight line production path was pointing us toward anyway. So it's really where we're going. And if you're -- if you kind of want to guess what production is likely to be in 2019, all you got to do, is take a straight line to where it's been in the last couple of years, and 65,000 in 2020, and you can probably pretty much nail what our forecast would be for 2019. So the fact that most of your analysts kind of said, well, the 2020 guidance that we provided yesterday was pretty much exactly where everybody expected. Well, that's no big surprise because it's just a straight line. So -- and 2019, I can guarantee, it will be pretty much exactly where everybody expected because that's just a straight line. But my -- the reason why we were heading towards 65,000 is really -- because the wells are turning out a bit better than we expected. So for the same number of wells that we intended to drill, we're getting a bit more production. So we might as well just kind of fess up and say, heck, we're heading towards 65,000. And really, it's my underlying bullishness. If I look at the oil macro, if you listen to any of my earnings calls over the previous 12 months, you know I've been consistently bullish on oil. And as I look today, I haven't looked at the WTI this morning, but generally, we're at 63,000 and change [Audio Gap] it means [Audio Gap] expected it to. So I continue to believe that we'll be at $70 WTI by 2020 or higher. And so in a rising oil price environment, we want to have the highest oil for your CAGR of any E&P company, because we think that will certainly be one of the constituents that drives share price growth, along with low debt and reasonable GAAP income. And so the oil macro is what's continuing to drive me towards 65,000 over 60,000. And so far, we have been directionally correct on the oil macro. So unless I see a change in the oil macro, we're going to stay with that reasonably aggressive oil growth forecast as opposed to scaling back to 65,000 and, if you will, conserving a little bit of capital. So that's the direction -- yes?

[Chan Wai, analyst]

Okay, yes, great. That's really helpful. And just a quick follow-up to Scott's prior question, and I'm almost afraid to ask given the straight line, and I think I've got a ruler somewhere. But I think historically, you said that the Bone Spring has not been factored into your 2020 guide, and just checking if that's still the case. And it sounds like from your prior commentary that, if you do continue to have great success of the Bone Spring, that it's likely to be some Wolfcamp CapEx reallocation versus kind of touching the target again?

[Mark Papa, executive]

Yes, I think you're right, Jeanine, yes. Don't be afraid to ask questions. But yes, probably what will happen at this point, I do not anticipate -- if we have spectacular results in this 3rd Bone Spring Sand, I do not anticipate that we'll come back and say, wow, we're going to up the growth from 65,000 to 70,000. I think all that will happen is, we'll just -- some of that growth will come from the 3rd Bone Sand as opposed to coming from the Wolfcamp. So it will just be -- the contribution to growth will come from a different zone.

[Operator]

I will hand the call back over to Mr. Papa. You may continue.

[Mark Papa, executive]

Okay. Thank you very much for listening. We're sorry we kept you a little bit over the 1-hour timeframe, but we look forward to talking everyone 3 months from now.

[George Glyphis, executive]

Thanks.

[Operator]

Thank you. This concludes today's conference call. You may now disconnect. Have a great day.