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 30, 2018, by dialing 855-859-2056 and entering the conference ID number of 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..

Thanks everyone, 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 risk and uncertainties that could affect our actual results and plans.

Many of these risks are beyond our control and are discussed in more detail in the Risk Factors and Forward-Looking Statement sections 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 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..

Thanks Hays. Good morning and welcome to Centennial's fourth quarter 2017 earnings call.

Our 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 from the quarter, and then, I will follow with my views regarding the oil macro, our strategy as a function of the macro and closing comments.

Now, I will ask George to review our financial results..

Thank you, Mark. During the fourth quarter we continue to successfully execute our six-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 volumes. Oil volumes as a percentage of total equivalent production was 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 price before hedges in Q4 compared to $44.95 in Q3.

The last of our legacy oil swaps went off at year-end, so we currently have full exposure to oil prices going forward. These operating expenses including workover costs 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 the upper end of our annual guidance range primarily as a result of a higher percentage of our total disposal of [water begin 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 costs 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 price 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 on 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 breakout in our guidance numbers for greater transparency.

The D&C expenditures were higher than we anticipated primarily as a result of a shift to drilling more extended laterals. We drilled more extended laterals in Q4 compared to previous three quarters combined and our initial extended lateral D&C estimates per well was simply too conservative.

Additionally, we have higher working interest in Q4 than originally forecast as a result of some good work by Centennial's land team and finally some cost from previously drilled wells carried over into Q4. Our fourth quarter closed out on very successful 2017.

Centennial's production exceeded the high-end of our annual guidance range which was a solid results given that we would increase production guidance on three separate occasions during the course of the year.

Per unit cost generally came in as expected after having lower unit cost guidance mid-year and D&C costs as noted were higher than we anticipated primarily because of greater cost associated with extended lateral activity.

That said, we will continue to shift our activity towards the 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 7500 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 and a coupon of 5.375% and at January 2026 maturity. Proceeds from the offering we used to fully repay borrowings under our revolving credit facility and pre-fund a portion of our 2018 development program.

At December 31, we had approximately $170 million of cash and $400 million of debt with nothing drawn on the revolver. And current with the bond offering, we voluntarily reduced the amount of 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 0.6 times.

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 a seventh-rig in February and expect to remain at seven-rig 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 costs 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 well and complete 75 to 85 gross wells during 2018.

Non-operated 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, our existing SWD wells and the 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 cost, 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 costs 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 transportation and other arrangements for our residue gas.

As a result of leasing and projected drilling activity in the Delaware basin, we believe that securing 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 transpiration services agreements for essentially all of our expected gross natural gas production in 2018 in order to ensure delivery to market. Centennial has agreement or extensions in place after 2018 and will monitor future needs of an ongoing basis.

Cash G&As per Boe is estimated at $2.20 to $2.70 per barrel as production volumes and measured notion of G&A growth continue to drive unit cost down. Non-cash stock-based compensation is estimated at $0.90 to a $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 are 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 in 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 at Occidental Petroleum and various international and domestic roles including Asset Manager of Oxy Permian. His public company experienced 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?.

Thank you, George. The fourth quarter represented another solid quarter and solid execution with Centennial. We brought strong well results online for both the northern and southern Delaware basins including an Avalon test, two successful Bone Spring delineation tests and a positive downspacing test in the Wolfcamp A.

During the quarter, Centennial operated six 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 third Bone Spring Sand in Reeves County.

We're excited about the Weaver which represents our first third Bone Spring Sand completion using enhanced completion techniques. Weaver was drilled with an approximately 9,400 foot lateral and was producing over 2,000 barrels of oil equivalent per day or approximately 1,500 barrels of oil per day during this 10 day online.

Based on its initial flowback which remains strong, the Weaver appears to be similar to our Wolfcamp A with regards to productivity. This is encouraging as we believe the third 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 brought online the Big House C 3H in the third Bone Spring Carbonate interval.

Located in the company's Miramar acreage, the Big House was drilled with a short lateral of approximately 4000 feet and reported an IP 30 of 800 barrels of oil equivalent per day consisting of 60% oil or 120 barrels of oil per 1000 foot of lateral.

Notably, we estimate that by adjusting the big house for an extended lateral, it would generate approximately a 45% pretax IRR at today's commodity price environment. Therefore, we plan to continue testing this zone and will drill an additional long lateral well during the year.

In addition to the Bone Spring, Centennial continue to deliver impressive results through it's Wolfcamp development across the entire position in Reeves County.

Targeting the upper Wolfcamp A, the Blackstone West 1H and 2H were drilled with an approximately 4100 foot lateral length and produced average IP 30s of over 1500 barrels of oil equivalent per day consisting of roughly 80% oil. On a per lateral foot basis, these wells delivered IP 30s of 342 and 263 barrels of oil 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 4150 feet in the Wolfcamp Lower A. This well achieved an IP 30 of approximately 1250 barrels of oil equivalent per day consisting of 88% oil.

On a per 1000 foot of lateral basis, this equates to 268 barrels of oil per day. Lastly in Reeves County, Centennial also reported an impressive initial downspacing test with the Big House A 4 57-60 1H and 2H. These wells were drilled at 660 foot spacing implying eight wells per section per zone.

With approximately 7000 foot laterals, the Big House 1H and 2H both generate IP 30s of approximately 2705 barrels of oil equivalent per day, and 2730 barrels of oil equivalent per day respectively, consisting of over 50% oil.

Additionally, these wells achieved approximately 200 barrels of oil per day and 206 barrels of oil per day on a per thousand foot basis and the two well pad had cumulative 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 downspacing 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 operated drilling program during September of last year and 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 4200 feet. This well achieved an IP 30 of approximately 1100 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 two well pad drilled in the second Bone Spring. These wells averaged approximately 4000 feet of lateral length and reported an IP 30 of just over 1000 barrels of oil equivalent per day per well.

On a per lateral foot basis, these wells averaged 210 barrels of oil per day for 1000 feet of lateral during the initial 30 days of production. We expect to continue to operate one 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 Lee County asset and underpin our decision to expand our position through the OneEnergy acquisition. Shooting to Slide 14, Centennial delivered strong reserve growth during 2017. Total proved reserves increased 125% to 186 million barrels of oil equivalent at year-end 2017.

Due to the combination of increased well performance and activity, we organically replaced over 950% of our 2017 production and an attractive drillbit F&D cost of $5.47 per barrel of oil equivalent. Year-over-year our proved reserve value on a PV-10 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 4000 net acres in Lea County for $95 million from OneEnergy 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 operating position with a high working interest of 95%. Additionally, we estimate the acquisition will add approximately 100 gross locations 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 heard Mark said before, we will only add acreage as it needs all three 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 an attractive price as we will not overpay for acreage.

We believe the OneEnergy acquisition needs all three 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 8600 net acres in Reeves County for approximately $140 million.

As you can see on this slide, this acreage is located on the Western portion of our position in Reeves County. The divestiture is largely non-operated 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 divesture is expected to close on March 1, 2018 subject to customary closing in terms and conditions.

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

Thanks Sean. Now I'll provide some thoughts regarding the oil macro picture and relate them to Centennial strategy. Since Centennial was just slightly over one-year-old as a fully functioning company, I also provided some perspective regarding how we made it up to our first year goals and what we expect to accomplish in our second year.

Oil prices have recently responded to the global inventories on around caused by tightening supply demand fundamentals and the focus now turns to 2018 U.S. oil supply growth. Many forecasting agencies operating U.S. oil growth of between 1.4 million and 2 million barrels of oil a 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 price. 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 target from 60,000 to 65,000 barrels oil per day based on our strong well results. We expect to accomplish this without increasing our rig count or capital commitments from our previous plan. I also ask you to focus on fossilized in our presentation we released last night.

Slide 5 outlines the nine 2017 company goals we articulated in March of 2017 you’ll know 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 estimate three times, established ourselves as the mid-cap technical leader in well completion technology, commercially tested two bone spring productive and goals and improved our acreage quality with several transactions.

Slides 11 and 12 compare our well results on a barrel oil per foot basis with other operators in the Southern Delaware. I’m particularly pleased that in one 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.

With outperforming and expenses M&A, we've added 100% IRR inventory [Technical Difficulty]. We 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 debt 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 ROE's and ROCE’'s this year. Thanks for listening and now we'll go to Q&A..

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

Congratulations on a really good quarter.

My question has to do with the third Bone Spring carbonate, understanding this early, do you have a feeling as to how extensive this particular target is A) for your acreage and B) for county?.

Yes, the third Bone Spring’s carbonate I would say is based on what we know today is extensive roughly maybe two-thirds of our acreage. And what I would tell you about that play is number one, I don’t want to over sell it right now. I’d say in baseball play, - the first well is what I say a single or double, it’s a not home run.

As we pointed out in the slide our presentation, the first well doesn't meet the economic threshold that’s competitive with the rest of our portfolio. It was a short lateral modeling in the case as long lateral two mile lateral we would have economics that would compete with the rest of our portfolio.

So our plans are likely in the fourth quarter of this year we would drill a two-mile lateral and we’ll 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 one other test here and see whether this really is - 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 third Bone Spring Sand and we would just identify the third Bone Spring carbonate as a potential additional Bone Spring target..

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

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’s going to be very heavily weighted to the Wolfcamp A and just the upper A and just is - our question in terms of if you do get success in the third 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 Bone Spring?.

Yes Scott excellent question. It looks like right now that the preliminary thought would be that we probably are setting ourselves up here for kind of parent-child drilling for the third bone sand and the upper Wolfcamp A if we had to make - you know guess rather by this 10 seconds.

And so you're correct, our program as we would define it right now is heavily weighted towards upper Wolfcamp A for 2018, but we’re going to drill a confirmation well in this third Bone Spring Sand sometime pretty quickly because of our really good result from the Weaver 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 then we would have initially expected and more a third bone sand well.

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 they'll be more third 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 that this 10 seconds is to what is likely to occur in 2018..

Are those well cost pretty comparable between the two zones?.

Yes. I mean the third bone is just slightly shallower but not that much so for the horse using hand grenades yes you can just say the well costs are comparable..

And just a question on the CapEx for 2018, there is a decent size number that is infrastructure spend.

And could you give us a little context around that, is some of that infrastructure spend that you’ll be doing this year benefit I guess wells down the road or should we assume on a go forward basis that amount to be associated with the well to well count..

Yes, Sean do you want to fill that question..

I think that - you can think of that infrastructure spend and kind of two buckets but the majority of which is a reoccurring 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 reduction in later years..

And then on your presentation I think on Page 20 you show those target ranges the net income system, net infrastructure spend on those average well cost is that right?.

Yes..

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

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

Yes Subash, again our view is - again we’re a little bit unusual company in that we started out with essentially zero debt. So as you know our current net debt is about 6% so we are outspending cash flow quite obviously in 2018.

We will likely outspend our cash flow in 2019 based on our model of 2019 we should achieve neutrality and that's based on roughly $65 WTI price in there.

And so we get the question a lot where - is your outspending cash flow that's bad our mode is we designed this company to come out is in our Genesis we see real 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 is 60,000 to 65,000 barrels of oil a 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 questions about your outspending cash flow when there we’re one of the lowest net debt companies and projected to be one of the lowest net debt companies even through 2019 and 2020. But yeah we should reach neutrality by 2019 or 2020..

And I guess repeat Irene's question that she asked on the carbonate to the bone spring sand how extensive or blanket you might - think it is or versatile channelized it might be across Reeves County?.

On the Bone Spring sand that looks to be covering probably roughly three-quarters of the Reeves County acreage - a very rough number. The question and again we had offset operators I think certainly Noble and I believe [Control] have also had some pretty good third Bone Spring sand results recently.

So it's a zone that is pervasive not just on our acreage but on acreage kind of around our area to. The question on our third Bone Spring sand is it is more of the courtside elements to it obviously when you use the word sand and a shale.

And so the question comes in as what is the spacing that you will get for 640 acre unit how many wells could you put in a 640 acre unit. Is it four wells, is it six wells so on and so forth so we’re going to have do some work on that. But I would say that this is a pretty meaningful result this third Bone Spring sand result.

This is not a one-off deal this looks like something that it’s going to turn out to be a pretty significant development on our acreage. And as noted the pro-well IRRs look quite attractive. So we're pretty excited about this result.

The carbonate just to touch on the carbonate for a minute nobody probably nobody to our knowledge nobody has really tested this third bone carbonate in the area maybe for 40 or 50 mile radius around our well. So the carbonate is really - I’ll call it kind of a semi wildcat.

So this is a true original test if you will so it is meaningful and that we’ve got a well that – is probably going to be commercial on a 2 mile lateral basis that nobody has tested for quite a large area. So we just have to see how that plays out and so, it’s a pretty neat that we do have that established also..

And 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 the Wolfcamp sands with all the intervals Wolfcamp sand still you know a target of viable zone that you may want to sequence somewhere between the Bone Spring and the Wolfcamp this year?.

The Wolfcamp sands or the Wolfcamp shale's or sales if you will are you talking about….

Yes, I was thinking about it’s probably closer the northern part of Texas, but X, Y's and if it gets down to your acreage and you know?.

Yes the X, Y doesn’t really exist on our acreage so that’s likely not a target on our acreage. Yes, that’s not one we’re going to be targeting really there are a couple other Bone Spring intervals that are potential on our acreage and of course we got the Wolfcamp B and C that are paying on our acreage.

But I guess in terms of new zones we may test another one or two Bone Spring intervals that could pop up that may potentially be pay intervals..

And do you think the decline rate is similar to the shale?.

We've got some production history on some of this third bone sand and yeah I’d say you know again horseshoes and hand grenades yeah are fairly similar..

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

Your customers are signing up some STE, 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 when do you think things get sideways in the basin in terms of getting gas out?.

Michael good question, yes, I mean everybody knows that the Apache is proceeding with developing our Alpine high area and that's obviously going to move - put a lot of gas into that long-haul hub which is going to be pretty much a very gassy played Alpine high will be.

And then you got certainly a lot of the casing head 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 one, getting our gas to long haul and the number two getting our gas away from long haul.

And so the increase that you're seeing in our GP&T estimates for 2018, as 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 gateway issues in Reeves County, you've got - you get your oil moved off lease and you get your NGLs moved off lease, and then can you get your gas moved off lease. Lease over a 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 pretty 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 a problem. So that's kind of the macroview, Michael, as we see it.

And then of course the other issue you have, and as we noticed on some of the other prominent, particular Delaware Players earnings calls, is water disposal, produced water disposal. That could trick 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 off properly and you're seeing that our LOE has moved up a little bit because of their disposal cost.

We feel, say, reasonably good that we've got our water disposal issues pretty well in hand, that it's something that we'd have to just continually focus on to make sure that somewhere year or two down the road, we don't have to shut in our oil because we can't get rid of the produced water..

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

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

And then just more on the productivity side. I mean, obviously it continues to trend up into the right.

Could you maybe talk about the least and greatest and lateral placement and completion side that's striving these continued gains?.

Yes. I've kind of got two answers on that. One is on the front technology side, I think that we've now reached a point where we're getting our laterals in zone like 96% of the lateral we just were supposed to be generating and we're now up to between 2,500 and 3,000 pounds of proppant per foot, and we're 100% slick water.

So, I think that we've 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 two or three years, you're going to see a 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 with frac technology or completion technology to get such improvements.

And that's one reason why I kind of think on a macro scale, that 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 U.S. oil production..

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

I feel very good about our position, and I think these two land transactions that we outlined today are relatively small, but I think did improve our position, get us more out of non-operated 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 Third Bone Spring Sand putting out in our inventory and getting us to 65,000 and beyond that post 2020. Then and saying, I'd like to double the size of the company with some big M&A transformative.

So at this juncture I would say it's not particularly likely that we're going to do some big transformative M&A.

Your next question comes from the line of [indiscernible] from Bank of America. Your line is open..

So Mark, you've see that as already linked employee compensation to return capital.

And just wondering if you could elaborate how it works down the chain? And just wanted to get you updated thoughts on outspend versus return on capital to shareholder debate and your thoughts on the value creation for an E&P?.

Yes. We get 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 cost including land and all those indirect costs, not just direct drilling costs.

And at the end of the year we do what kind of ROR did we get on the entire capital program. And if we got to a good ROR then a bonus is higher than if we got accrual ROR.

So it does make everybody in the company like say down to lease operators focus on you know if you spend too much money in a capital program everybody's bonus and 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 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 or a much more attractive to me and that's why I try to make the point in this call that this, this Third Bone Spring Sand is just the kind of things that I think is really value creating because it's essentially free inventory this will.

I mean it was already on our acreage and now we've added it to our inventory, so those are the kind of things that I really that like to do as opposed to trying to 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 this technical efficiency because I think that allows you to get the best ROR in a capital program so that's why we have so many slides in our presentation about what is our well quality compared to others because I think that really ties into the technical efficiency.

And the capital spend does not bother me at all for 2018 and 2019 because again because we designed the company to come out of the box with no debt.

So what does have my attention is, the absolute level of doubt and the net debt to total cap ratio when I have one, max amount of kind of 25% net debt to total cap anything off 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 that I believe will drive us to maximum share price..

And quick one for Sean.

Sean on the oil cut, the river well did I hear you say 75%? And then on what extent are you planning to use in-basin sand 2018?.

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

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

So well interference issues stemming for me that their parent child relationships are too tighter spacing is company top core earnings experience.

And your market Sean, I would love to hear your thoughts on how you assess these risks for if you see the industry as a whole and how you plan to mitigate these risk as you move into a fulfill development? Thanks..

We're currently surveying 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 880 or 660. As you know our inventory that we had promulgated about a year ago was all based on 880s and we've done some 660 spacing tests.

We're currently doing a lot of tests right now particularly on the upper A and lower A on parent/child issues there to see what is are there parent/child issues or not? And then with this Third Bone Sand, if we do a Third Bone Sand and upper A, question come up would there be parent/Child issues with those two if we did those together.

So, in answer to question, I would say that across the industry, I believe parent/child issues are real, and certainly in the middle and Delaware basin is where it's most similar because got these stack pays the real.

I have always believed and we're seeing clearly in Eagle Ford now even with some of the earnings results it just come out in the last several days that a lot of companies have promulgated there well spacing is much too tightly. And we're seeing a lot of well interference there.

So, and I predict, you'll see more of that over the next year or two that the companies are going to have to say gee whiz, I thought my spacing could be this tight? But now after drilling some wells and going say my spacing has to be a lot wide than what I had previously said. So I think this is a real issue.

All I can say is, we were studying it at Centennial. I'm just very glad that we promulgated our first set of kind of inventory list we came out with an 880 spacing which I think is a very conservative space in for the Wolfcamp. So that's just a generalized statement..

I appreciate that. Switching topics little bit, talked a lot in this call already not third bone carbonate sands but we've also started to hear that Felix and some other operators are having some pretty nice success with the Third Bone Spring Shale kind of the Eastern Delaware front.

And I just want to confirm that this is actually something different than a Third Bone Carbonate that you guys tested? And if you see this formation potential across your acreage and if you plan to test it?.

I'll confirm that this is different than a Third Bone Shale. That it is Third Bone carbonate. There is a Third Bone Shale different than the Third Bone carbonate. We have a Third Bone shale potential target on our acreage. And that maybe a zone that we may test perhaps later this year or perhaps early in 2019.

So, yes, there are there are several packages like that in this third Bone section. And so, I'm gratified to hear that some people are making the third Bone share work because that they will give us more confidence that we might test on our acreage..

And so sir, we have a last question coming from the line of Jeanine Wai from Citigroup. Your line is open..

In terms of new 2020 oil production target, you discuss that part of it is related to Centennials response to the 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 outspends a little bit faster? I am 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?.

Yes, Jeanine. Number one, I mean if - I've always said that, you can - you can't predict what our 2018 and 2019 oil production target was by just kind of taken a straight line to 60,000 barrels a 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 they're on - there on a broad path to 65,000 barrels a day in 2020 anyway. So the fact that we've now kind of fessed up that the target 65 instead of 20 is, I think just for 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 want to guess what production is likely to be in 2019, all you got to do is take a straight line, whereas it's been the last couple years and 65,000 in 2020 and you can proudly much nail what our forecast will be for 2019.

So the fact that most of the analyst 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. And 2019, I can guarantee you will be pretty much exactly where everybody expected because that's just the straight line.

But the reason why we were heading for 65 is, really because the wells have turned 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 may as well just kind of fess up and say that we’re heading toward 65.

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 WTI this morning, but generally we're at 63 interchange. I mean [Technical Difficulty] 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 load out and reasonable gap income.

And so the oil macro is what's continuing to drive me towards 65 over 60. 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 and if you will conserve in a little bit of capital.

So that's the direction….

And just a quick follow up to Scott’s prior question and I'm almost afraid to ask is it a straight line. And I think they are somewhere, but I think historically you said that the Bone Spring has not been factored into your 2020 guide and just checking in at 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 capital allocation versus kind of touching the target again?.

Yes, I think you're right Jeanine. You'll not be afraid to ask questions. At this point I do not anticipate if we have spectacular results in this third Bone Spring Sand, I do not anticipate that we'll come back and say, we're going up the growth from 65 to 70.

I think all that will happen is, we'll just some of that growth will come from the Third Bone Sand as opposed to coming from the Wolfcamp. So it'll just be - the contribution growth will come from a different zone..

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

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

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