Good morning, and welcome to Centennial Resource Development's conference call to discuss its third quarter 2018 earnings. This call is being recorded. A replay of the call will be accessible until November 20, 2018, by dialing 855-859-2056 and entering the conference ID number, 2186036, 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..

Thanks, Mary Grace, and thank you all for joining us on the company's third quarter 2018 earnings call. Presenting on the call today are Mark Papa, our Chairman and Chief Executive Officer; George Glyphis, our Chief Financial Officer; and Sean Smith, our Chief Operating Officer.

Yesterday, November 5, we filed a Form 8-K with an earnings release reporting third quarter 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 the forward-looking statement section of our filings with the SEC, including our annual report on Form 10-K for the year-ended December 31, 2017.

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

George will first discuss our quarterly financial results, hedge position and liquidity. Sean will then provide an operational update, including well results, Midstream status and tactical acquisitions.

And then I'll follow with my macro view, our strategy emanating for the macro, comments regarding CDEV's inventory maintenance plans and closing items. Now I'll ask George to review our financial results..

Thank you, Mark. As you can reference on Slide 14 of the earnings presentation, Centennial's daily oil production for Q3 averaged approximately 36,000 barrels per day, which was up 15% from Q2. Average oil equivalent production totaled approximately 62,900 barrels per day, a 9% increase quarter-over-quarter.

We spud 18 wells and completed 22 during Q3, which was in line with our expectations. Ethane recovery, which started in Q2 of this year, continued during Q3. Oil as a percentage of total production was 57% compared to 54% in Q2.

The increase in oil mix resulted primarily from the fact that a majority of our activity was located on our oilier legacy Centennial and Lea County acreage. Revenues for the third quarter totaled approximately $235 million, which was 8% higher than Q2. Higher oil sales volumes were offset by a significantly wider Midland-Cushing differential.

Centennial's average realized oil price before basis hedges in Q3 was $55.68 per barrel, which was 9% lower than Q2, but approximately 24% above the prior year period. Inclusive of the impact of basis hedges, Centennial's realized price for the quarter was approximately 84% of NYMEX down from 92% in Q2.

We continue to be unhedged on fixed price WTI and believe the global oil market remains tight from a macro supply demand standpoint. Turning to cost. Through the end of Q3, our unit costs are tracking toward the lower half of our previously reduced guidance ranges.

LOE was $4.09 per BOE in Q3, a 12% increase over Q2, resulting from higher workover expense, equipment rentals and water handling costs. GP&T expense of $2.78 per BOE was down 5% quarter-over-quarter and cash G&A increased by approximately 9% to $2.02 as a result of personnel additions. DD&A costs are relatively flat at $14.41 per BOE.

Adjusted EBITDAX totaled approximately $178 million for Q3. This was 8% higher than the prior quarter despite the 9% decline in oil realizations, primarily due to higher production and solid cost control.

GAAP net income attributable to our Class A common stock totaled approximately $39 million or $0.15 per diluted share compared to $0.24 and $0.06 per share in Q2 '18 and Q3 '17, respectively. Net income for the quarter was impacted by two items. First, we incurred a $9.6 million loss on derivative instruments primarily tied to our oil bases hedges.

This comprised approximately $18.4 million of noncash mark-to-market derivative charges that were offset by $8.8 million of positive cash realizations during the quarter. Second, we incurred an $8.6 million abandonment charge because we left some acreage expire that we did not plan to drill.

Turning to CapEx, Centennial incurred approximately $274 million of total capital expenditures during the quarter compared to $203 million in Q2. This increase was driven primarily by higher completion activity and significantly higher working interest in wells that were spud and completed.

Additionally, the average lateral length of completed wells increased from approximately 7,100 feet in Q2 to 7,700 feet in Q3. Overall, D&C CapEx was approximately $222 million and well level facilities, infrastructure, seismic acquisitions, land and other capital totaled approximately $52 million.

We are pleased with our capital spending pace year-to-date and are maintaining our original full year CapEx guidance for 2018. On Slide 12 of the presentation, we summarize our capital structure, maturity profile and liquidity.

At September 30, we had approximately $59 million of cash, $140 million of borrowings under the revolving credit facility and $400 million of senior unsecured notes. At quarter's end, pro forma for our $800 million elected commitments on the credit facility, we had $718 million of liquidity.

Centennial's net debt to book capitalization was 13% and net debt to Q3 annualized EBITDAX was 0.7x. These credit metrics represent one of the lowest leverage profiles of the Permian peers. And with that, I'll turn the call over to Sean Smith to review operations..

one, core acreage; two, accretive in value; and three, at a reasonable acquisition price. Centennial also acquired 820 net acres in Lea County through a separate - through two separate transactions from undisclosed third parties for a combined purchase price of $26 million.

Importantly, we estimate our Lea County acquisitions were consummated at an attractive adjusted purchase price of approximately $26,000 per net acre, which includes associated production, and compares favorably to recent comps in the area.

The contiguous bolt-on nature of both properties increases Centennial's working interest on its existing acreage, and also allows for the drilling of extended laterals, significantly increasing the potential wellhead IRRs.

Additionally, a portion of the acquired acreage in the [indiscernible] area in Western Lea County, increases Centennial's working interest in its recently drilled Cheddar 3rd Bone Spring Federal Com 1H well.

The Cheddar well was drilled with an approximate 9,600 foot lateral and achieved an IP30 of 1,700 barrels of oil equivalent, 75% oil, and continues to produce a strong rate with an IP60 of almost 1,600 barrels of oil equivalent per day, 75% oil.

All of these transactions are consistent with our strategy of targeting tactical bolt-on acquisitions, adjacent to our existing positions, which we know well. As a reminder, our goal is not to be the biggest company in the Permian Basin, but to be the most technically proficient operator in the division - basin.

We believe this strategy of targeting smaller bolt-on acquisitions combined with organic inventory adds will differentiate Centennial versus its peers, while providing superior GAAP returns along the way. With that, I will turn the call back over to Mark..

First, exploring our uphold section on our existing acreage as we've already successfully done by adding the prolific 3rd Bone Spring Sand. This is effectively free inventory. In early 2019, we'll test two additional shallower bone spring intervals.

The second way will be through tactical acreage acquisitions as the three mentioned on this call and the one energy acquisition executed in the first quarter. Combined with organic leasing, we have significantly increased our drilling inventory this year, replacing 4x our 2018 wells drilled without resorting to a big corporate M&A.

You should expect us to follow a similar strategy in future years. In summary, I'd like to make 7 points. First, our oil volume growth is on track and is one of the higher, perhaps the highest rates in the entire industry.

Although we won't provide specific 2019 volume and CapEx guidance until February, since you know our 2018 oil volumes and our 2020 oil target of 65,000, it shouldn't be hard to estimate our 2019 oil target. And we'll likely add 2.5 rigs next year to achieve that goal.

Second, we believe we're the best positioned mid-cap regarding both oil and gas Permian pipeline egress. Third, we're one of the few E&Ps whose full year 2018 CapEx continues to be in line with our original February estimate. Fourth, we believe our likely well - our well quality is the best among the Delaware Basin mid-caps.

This is detailed on Slide 9 of our slides released this morning. More importantly, for those of you that are focused on the parent-child issue, most of our wells completed this quarter were child wells, and they are performing in line with our child-type curves.

Fifth, all of our unit costs continue to look positive relative to guidance that we lowered last quarter. Sixth, we have the lowest debt in the Permian peer group. And finally, seventh, although this year's GAAP ROE and ROCE aren't great, we expect to post attractive GAAP returns in 2020 assuming $75 WTI.

Thanks for listening, and now we will go to Q&A.

Mary Grace, do you want to queue up the Q&A?.

[Operator Instructions]. And the first question comes from the line of Subash Chandra from Guggenheim..

As you sort of look to '19 and it looks like '18, it's coming in on the cost side within guidance.

But, I guess, at the margin, what do you see changing? What are you most concerned about in terms of inflation?.

Yes, Subash. As we go to 2019, in terms of the - in terms of an operating cost side, we don't see a lot changing there. It is possible our LOE may trend up a bit, although don't take that as any directional sign until we really come up with something in February. Our G&A on a unit basis, I expect, is going to trend down relative to 2018 levels.

We may see the GP&T trend up a bit and that would just be related to the gas FTE as we have a full year there, but not by a huge amount. So I'd say unit costs, nothing dramatic in way of anything dramatic movement. On the capital side, we continue to see no real pressure on the hydraulic fracturing side.

So at least as we would project now, relatively flattish for '19 on that. And that's maybe the single biggest component of our well costs. Steel costs, as I'm sure you've heard from everyone, are likely to inflate. But I would say, overall, just a moderate degree of inflation on the capital cost side as we go forward.

Now, our CapEx will certainly increase year-over-year because our rig activity is going to increase. So that's the directional signs that I'd give you at this point..

Okay. And as a follow-up. I guess, as you launch development, you have the child wells now. I assume there'll be a sort of increased proportion of your drilling program. So just in terms of cube development, how you think about that? Is it necessary, is it not? There seems to be two camps there.

And is that something that you would need to do or never need to do in your program?.

Yes. Just to may be give some clarification. And I believe this likely is not just a typical thing for Centennial, but for the entire Permian Basin.

The concept of parent wells being the unbounded wells, I think, as you really for 2018 and certainly, as you move into 2019 and 2020, there are likely to be very, very few percentage of the wells drilled by Centennial or by anybody in the Permian that are going be parent wells.

To give you just a rough idea, as we look into 2018 and really 2019, perhaps 15% of the wells that we drilled in '18 and likely drill in '19 are really parent wells. So that tells you that the overwhelming percentage of the wells we're currently drilling and certainly drilling next year are really going to be child wells.

And I think that applies to the entire Permian Basin. So if you recall from past years, you kept seeing type curves of these unbounded wells with these very high IRRs. There are a very few unbounded wells pretty much anywhere, probably at any shale play on a go-forward basis.

So we're stepping into a situation where we won't be really cube drilling, but we're going to be pattern drilling, certainly where essentially all of our wells or very high percentage of our wells are going to be wells where the type curves are going to be, shall we say discounted-type curves from parent wells.

And so that is something that we clearly will be factoring in as we figure out how many wells does it take to achieve our production growth targets on a go-forward basis. So, hopefully, that gives you some clarification to what you're asking..

Our next question comes from the line of Rob Morris..

On the topic of parent/child wells. On the two well pad you did at the Tour Bus 23, those 2 wells were in line or better than what it'd been historically your one section of parent wells in that area.

So first question is what was the spacing on those wells? And then two, when you mentioned it, all of your child wells have been in line with your type curves.

What are you assuming as far as spacing and degradation on child wells versus parent wells?.

Yes. On the second part of your question, Bob, I don't want to get into specifics as to what degree of degradation we're talking about there, but in general terms - generally talking about, about a 20% degradation, relative to a parent well for a typical child well. So it's a relatively significant amount.

On the spacing side, Sean, do you want to respond to Bob's question there about Tour Bus?.

Sure. I appreciate you pointing that out. The Tour Bus section, in fact, we've six wells in that Tour Bus section right now, as of those two that we just released. And so it's certainly going to be a more developed section and as you pointed out, these two wells are outperforming some of their more previously drilled wells.

So we're pretty pleased with that. I think it's, again, just about how we've matured as a company in the area and got a little bit more effective and efficient with how we're completing wells. On the spacing basis, generally, these wells are in the 80-spacing range..

Okay. And then my follow-up is just on the Pirate State well. I think, that's the 1st Bone Spring well that you've operated here.

And so as you look at that as your organic inventory growth, what is your delineation plan on that? And what could that potentially add to that organic inventory as you go forward? I know you had the 3rd Bone Spring test, but on the 1st Bone Spring well there, how do you think about that delineation and the organic inventory?.

Yes.

Sean?.

Sure. We're definitely very excited about the results. This is the first operated well in the 1st Bone Spring that we've announced. And it's certainly a positive surprise. We have not put in as of last inventory account that we had published. We didn't have any 1st Bone Spring in New Mexico accounted.

So this will certainly add inventory to our base organic inventory count. I think it could be over a portion of the New Mexico acreage, if we were to try and round things, maybe it's 1/2 or 1/3 or so of the acreage position, we think, has potential for 1st Bone Spring..

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

Mark, my question for - you guys continue to do a great job, organically, of more than replacing what the wells that you have been drilling by adding that.

Just wondering is that the plan you have been accomplished and be able to continue to do that in the next few years?.

Yes, Neal. If I had to point out one item that I would say is the most significant item on this particular earnings, it really is that slide that shows our replacement of inventory, where we're talking about 4x replacement of our inventory.

You've seen a huge trend here of consolidation that's just happened in the last couple of months and really in the last couple of weeks or so. And a lot of people say there's two reasons for that consolidation. One is while you get to lower your unit cost by taking cost out of the system.

Well, number one, we've got a cost slide in there that shows we're already pretty much the lowest unit cost person in the Permian. So no reason to consolidate there for us. And the second thing is people say, we can grow your inventory that way.

You really aren't growing your inventory because if you do an M&A, you become, let's say, twice as big, but you're producing twice as much. So you really haven't done anything for your years of inventory. I strongly believe that the way to grow your inventory is through tactical acquisitions and looking at uphold zones.

And I think it's just quite phenomenal that we've replaced 4x of our inventory this year, and I would say that easily puts us in first place relative to pretty much any other E&P company, and we've done it at really attractive cost. Because the vast majority that was essentially free inventory, the 3rd Bone Spring Sand.

And so your question is, can we do that on a go-forward basis, is that our plan? And clearly, it is for 2019. Hopefully, we get lucky in this 2nd Bone Spring carbonate and the other shallower bone spring interval we're going to test in 2019, we'll see whether we can add additional free inventory there.

We have already have a test in that 3rd Bone Spring Carbonate that kind of indicates with a 2-mile lateral that's likely to be an economic venture for us. So we've a good chance there. But I think you can expect CDEV on a go-forward basis to grow the inventory by that combination of tactical acquisitions and testing uphold zones.

And that ultimately should give us a leg up on generating positive ROEs and ROCEs..

Great answer. Great color, Mark. And then maybe one last one for Sean. Sean, looking at that Slide 8.

Just broader question, how homogenous do you sort of look at that general area? When I look at from Big House well three all the way down to the War Eagle, I'm just wondering when you sort of, now that you've gone through most of that Southern area of yours, how homogenous do you view this area?.

Specifically, the southern area or the area between the Big House and the War Eagle?.

Kind of that whole position over there, between the two?.

Okay. Yes, so I think the Wolfcamp A across that entire position is more homogeneous than the other zones. I think the Wolfcamp B and C are a little bit more heterogeneous, meaning they're not as contiguous across the entire position. But I feel very good about the results, obviously, from both the Big House 3 well pad as well as the War Eagle.

That's one of the better wells down to the south there and it continues to add some additional inventory potential to the southern position, and I think there's a lot of upside down there based on that well result..

And our next question is from Irene Haas from Imperial Capital..

So my question is - in terms of rig cadence, you're going to add 2.5 rigs next year '19, and how should we look at 2020? Would it be sort of a flattish rig count by then?.

Who? Sean, do you want to give some direction of where we project that that far? Or do we even have a projection?.

We haven't really given firm specifics on what we're going to do in 2020. I think, the assumption of going to 2.5 additional rigs next year is approximately right, in general. But we haven't given our 2019 guidance either. So that's the right indication of where we're going.

I would assume that we would add additional rigs going into 2020, but haven't given a specific number..

And our next question from Leo Mariani from NatAlliance Securities..

Quick question here on oil mix. Obviously, the numbers bounced around a little bit here during 2018.

Just wanted to get a sense of where do you think that goes as we get into the fourth quarter here?.

George or Sean, do you want to field that?.

Yes. Sure, Mark. It's George. I think the mix for Q4 will be relatively consistent with what we saw this quarter. What we saw this quarter was a shift in terms of our project areas to areas where we were seeing more oil mix relative to the higher GOR area, what we call Miramar, which is part of the legacy Silverback acquisition.

So we anticipate that, that 57% for the quarter is probably a reasonable assumption for Q4..

Okay. And then just jumping over to the acquisitions here that you guys made. Just to be clear, I mean, it sounds like that the payments for these are going to be 4Q and not 3Q in terms of that spend. And then I guess just wanted to just clarify. I know that you guys do have some leasehold spend designated in the budget.

Are these acquisitions that you made part of that or these sort of in addition to the budget?.

Yes. From a budgeting standpoint, we initially anticipated that we'd be spending anywhere from $50 million to $70 million from a land standpoint. And what we've seen is that organic leasing effort, as you would expect, is becoming more and more difficult over time.

And so part of the way we think about some of the tactical acquisitions, the bolt-on acquisitions is really supplanting that organic leasing effort that was not materializing in the amounts that we anticipated in the beginning of the year. So I think that's part of the mix there..

Okay. So just to be clear on that. Basically, lower organic leasehold spend, but then obviously, I guess, you get the acquisitions, which kind of makes up for that, I mean - and then a little bit more.

Is that kind of a good way to think about it?.

Yes. I think, that's right..

Okay. And I guess, obviously, you guys also just spoke about other opportunities out there, where you're not disclosing all of the purchase price information, which, obviously, is competitive process going on.

I mean, maybe just high level, I mean, are you seeing a fair number of these similar type of bolt-ons that we could see from you guys in the next few quarters?.

I think, we may do one more before the end of the year, but there's not like 3 or 4 that we're going to consummate over the next quarter. So it's not a massive deal flow at this time..

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

The War Eagle well looks pretty impressive. A good amount above your type curve.

Can you talk - is - with that success, do you plan on putting a little bit more activity down there? What is your plans on that southern part in that Big Chief area going forward?.

Yes.

Sean?.

You bet. So we do plan on putting a little bit more capital down there towards the end of this year. And certainly, going into next year based on that well. I think we had some success in early '18 and even late '17 down in that area, but this well certainly prompts even additional activity.

We weren't pressured by any lease expires to get down here earlier on. And - but this result certainly dictates that we would divert capital towards this area a bit more..

Okay.

And it is slightly oilier down there, right?.

It is..

Yes. Okay. And as a follow-up on, obviously, you talked about looking at the carbonates, 2nd Bone Spring, doing some tests in early '19. And when you step back and look at the success you've had in the 3rd Bone Spring Sand, potential for the carbonates, the Wolfcamp A, B.

How do you look at - when do we kind of start playing on sort of long-range full development? And being careful about the interaction between some of these zones?.

Well, for the 3rd Bone Sand, that we're already planning on developing on a full scale. And that is one where we're looking at developing jointly with the Upper Wolfcamp A on their. So that one we're really rolling out into full development. The 3rd Bone Carbonate is really going to depend on this longer lateral test.

And if it does prove commercial, then that's a good news on one hand, Scott, because, obviously, we've got some more free inventory. But then it adds another complication because now we've got another zone that could create some additional parent-child issues on a go-forward basis.

So it's just something we'll have to integrate into an ultimate development plan. But first thing is to really drill a long lateral and see if it works. And again, if you go back last year, we drilled a 1-mile lateral in that particular zone, the 3rd Bone Carbonate. And it was - I guess, it was a teaser.

It was a semicommercial well that was kind of borderline and that was back when oil was $45, $50. And the math said, if we drilled a 2-mile lateral, it would get over the threshold for economics. So we do have a fair amount of hope that, that one should turn out to be okay..

So specifically with that in mind, how do you look at the opportunity when you step back? And if the two mile is commercial, but certainly the returns can't compete with some of the other intervals, would you think about integrating it into the development plan? And obviously accepting a little bit lower return? Or would you basically risk that it being a child well down the future and the economics are lower, so will worry about that later? So are you going to maximize IRR? Or would you rather maximize the resource if it's marginally commercial?.

Yes. Yes, I probably can't answer that until we see what kind of results we have from the well, Scott. I'd probably be just speculating. So ask me again once I get that two mile lateral results..

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

Mark, maybe can you help us understand the benefits of reaching your target of 65,000 barrels of oil equivalent per day before you start to moderate growth, production growth? And then I assume this provides you enough scale to better leverage service cost, infrastructure, marketers, et cetera.

Why is that the right number in your thinking and also maybe probably an additional context and how we should think about what is a strong, but not in your net oil production growth starting in 2021?.

Yes. The 65,000 barrels a day, Will, when we set that target 2 to 3 years ago, it was a bit of an arbitrary target. The goal there was to create a company with enough mass, Will, where you basically had a company that had enough bulk really to really attract enough investor attention.

It wasn't really scale to be able to lower unit cost, because we've - at our current scale, as I mentioned earlier, on the call, we're already one of the lowest unit cost people in the Permian, and we've got a slide in our presentation that kind of shows it already. It's really just to have a significant scale to go forward.

And that number could have easily been 60,000 barrels a day, it could have easily been 70,000 barrels a day, when we picked it 2 to 3 years ago. 65,000 was a number, frankly, that I selected based on what I thought could be reasonably developed based on the acreage we had.

And we've just adhered to that number, and so - and we continue to adhere to that number. And it's - we hit our target every year as to get to that number. But it's a very high CAGR for an oil growth rate, and we certainly have said that we can't extend that high CAGR growth rate through, say, 2025.

No company could achieve that kind of oil growth rate for - extending it kind of forever. So we've always said that when we go post 2020, we will inflect and kind of change spots a little bit as a company, and we'll be likely initiate a dividend and go to a high, but less high than current, growth rate for the period of '21 through '25.

But we haven't specified what that is. But it won't be the asymptotic production growth rate that we're currently on. So, hopefully, that gives you a little bit of explanation. And we do expect to - sometime during 2020 to reach cash flow neutrality if one believes WTI is $75 that year.

And then we'll become a bit of a different company at that point in time..

Sorry, I guess that was part of my next question. You, obviously, laid out that post 2020, passed as positive free cash flow and institution of dividends. But based on your comments, it sounds like you could at some point reach cash flow neutrality in 2020, not essentially for the full year.

And it sounds like - maybe help us understand the price, I think you said, $75 WTI.

But what are some of the cost inflation assumptions that are baked into that analysis?.

Well, on the capital cost side, we've kind of given you what our directional thinking is for 2019 that, particularly on a frac side, which is the biggest component, we don't see a high level of inflation next year. And we haven't got - we're not forecasting massive cost inflation going into 2020 versus 2019.

So that's the best directional guidance I can give you. But we are forecasting an activity step-up in 2020 versus 2019. Again, it's a bit unspecified. But there will be a step up to achieve the growth in 2020 versus 2019. So that's the best kind of directional guidance I can give you at this point in time.

But yes, our internal models do show us that sometime during 2020, we reach cash flow neutrality, assuming $75 WTI..

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

Building on an earlier question on the Northern Delaware, now that you've had the assets in-house for over a year, could you comment on how your views on inventory, debts and order of development have changed? And could you also outline the remaining delineation of spacing initiatives you have for this asset over the next year?.

Yes. I'll just answer and then Sean can chime in a little bit. Yes, one of the - I'd say one of the drawbacks we have up that - number one, we're, obviously, making very, very good wells up there. I mean, that should be apparent from this press release.

So in terms of our ability to - of our technical team to pivot from Southern Delaware to Northern Delaware and accomplish the goal of making good wells, I think that we've already proven. But one of the drawbacks we have up there is we have a relatively small acreage footprint.

And most of the wells that we're kind of forced to drill up there are really 1-mile laterals as opposed to 2-mile laterals, just because our acreage footprint isn't that big. So we love to have a bigger acreage footprint up there, but we don't. So we are constrained in our lateral length up there, unfortunately.

But the good news is, in the acreage we have, it's really good quality. And so we generally have 5 or 6 zones that pay up there, and including now the 1st Bone up there.

So for the limited acreage that we have, we have quite a few locations and they're probably all, not all - I shouldn't say all, but a high percentage of the wells we drill are probably going to be pretty darn good wells on a barrels of oil per lateral foot basis. As you seem like this Cheddar well and then the 1st Bone well we quoted.

So at this juncture, we're still going to be running just one rig up there.

Whether we really have enough acreage to move the second rig up there is a little bit problematical, but we'll do what we can with the acreage we have and looking to tackle on bits and pieces, but it's tough letting and the ability to add acreage certainly in the federal lease sale is all but impossible, as you saw from the results of the last federal lease sale there unless you're willing to pay $80,000 an acre for some of this stuff.

So that would be the description I would have. I think you can expect us to continue to have very, very good well results from relatively short laterals up there, but it's going to be difficult to significantly add to our acreage position in a massive way. So that would be my overview of kind of where we stand in the Northern Delaware..

And then perhaps from my follow-up with Sean.

Regarding the Big House pad at Miramar, was the Wolfcamp B interval expected to be an earlier interval predrill?.

Yes. What we see in Miramar is that generally the Wolfcamp A has a slightly higher GOR than the Wolfcamp B or C in that area. So that was expected and is performing in line from the percent oil basis. But above, you can see our previously drilled wells in that area. So pleased with the result, but the percent oil was in line with our expectations..

And then, I'm showing that it's about 9:55. So I think we've got time for one more question, Mary Grace..

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

Just a couple from me. Maybe just to build on one of the prior questions a little bit. I know you talked about - a bit about longer-term growth.

But as you transition to free cash neutrality, how do you envision a longer-term shareholder returns of the mid-cap company?.

Yes. Michael, I think - again, as you look at Centennial, I've been pretty explicit saying we don't want to be the biggest company in the Permian Basin. I think that there are - there's a lot of room to add inventory in the Permian Basin, similar to what we've done this year, when we're very talking about 4x on our location adds.

I'm not saying every year, we're going to add 4x on locations. That's - I hope we can, but that's a pretty outrageous positive add this year.

But I think that we can continue to have significant location adds year after year because we're not that big, just by taking out acreage positions of private equity players or taking out acreage positions of other companies that really the acreage doesn't fit their particular profile. So we can continue to grow that way.

And I think as you get post 2020, after we have this phenomenal growth run, we have a more moderate, but steady growth to become a dividend-paying company.

And if indeed, the oil price cooperates as we think it does, and then perhaps levels off at about a $75 WTI or even a $70 WTI, who knows, then, I think that because we haven't done a value-destructive M&A where we've issued massive amounts of equity or taken on massive amounts of debt, and we've added inventory, essentially for free through these uphold zones, I think that we will have an advantaged ROE and ROCE on a GAAP basis in a long term kind of a situation.

So I think that we will turn into a growth company with high GAAP returns relative to peer companies. And I think we've demonstrated the technical confidence to make some of the best wells in the Permian.

And we've also demonstrated good confidence to handle both the gas and the oil egress as one of the better players in the Permian to maneuver around this issue. So I think all around, we've got pretty well buttoned up well-positioned company for the long run..

Got you. And then just a quick one on the marketing side. You've moved, obviously, quickly on the gas FTE side.

But can you talk about your comfortable level as it relates to the fractionation capacity?.

Yes. I can just give you an overview. I mean, essentially, all of our gas is processed by EagleClaw. And EagleClaw has a pretty, shall we say, a premium position in terms of being in the queue for fractionation at Mont Belvieu, and we feel that we're at the - pretty well, at the front end of the queue in terms of priority for fractionation.

So at this point, that's not an issue that worries us..

And this is Hays. Just wanted to thank everybody for joining today's call. Feel free to give us a call if you have any questions. We're handing back to Mary Grace to conclude. Thank you..

Ladies and gentlemen, we thank you all for participating. This concludes the conference call. You may now disconnect. Have a great day..