Good morning and welcome to Centennial Resource Development's Conference Call to discuss the Second Quarter 2017 Earnings. Today's call is being recorded. A replay of the call will be available until August 22, 2017, by dialing 855-859-2056 and entering the conference ID number of 54491921 or by visiting Centennial's web site at www.cdevinc.com. At this time, I will turn the call over to Hays Mabry, Centennial's Director of Investor Relations for opening remarks. Please go ahead.

Thanks, Kayla, and thank you all for joining us on the company's second quarter 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 August 7, we filed a Form 8-K with an earnings release reporting second quarter 2017 earnings results for the company and first quarter 2017 operational results for our subsidiary, Centennial Resource Production LLC. We also posted an earnings presentation to our web site that we will reference during today's call. You can find the presentation on our web site 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 sections of our filings with the Securities and Exchange Commission. Including our Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on March 23, 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 web site. With that, I'll turn the call over to Mr. Mark Papa, Chairman and CEO.

Thanks Hays. Good morning and welcome to Centennial's second quarter 2017 earnings call. Our presentation sequence on this call will be as follows; George will first discuss our second quarter financial results, capital structure and revised 2017 guidance. Sean will then provide an operational update, 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 second quarter financial results.

Thank you, Mark. As you can reference on page 9 of the earnings presentation, average oil production for the second quarter was 17,435 barrels per day, a 66% increase compared to approximately 10,500 barrels per day during the first quarter. Average oil equivalent production for the quarter totaled approximately 29,665 barrels per day, a 61% increase compared to the first quarter. Oil volumes for the second quarter increased to approximately 59% of total production, compared to 57% in Q1, as our second quarter completions were more heavily weighted towards lower GOR acreage, where we saw some outstanding well results. These excellent production results were driven by three factors; first, overall well performance continued to exceed our expectations. Second, drilling and completion efficiencies allowed us to bring more wells online than we anticipated. And finally, we had more rigs running in Q2 on average, compared to the first quarter. Because of the strong production in operational efficiencies gained to date, we have deferred adding our previously planned seventh rig this year, and will instead move one of our six rigs from Reeves County to Lea County in early September, to begin development on our Northern Delaware acreage. Revenues for the second quarter were $91 million compared to $61 million in the first quarter. This 49% increase was driven by higher sales volumes. Our average realized oil price, excluding the impact of commodity derivative transactions declined by approximately 10% quarter-over-quarter to $44.58 per barrel, as a result of lower oil prices during the period. Lease operating expenses, including workover costs totaled approximately $8.3 million for the second quarter or $3.06 per BOE. This 30% per unit decline compared to Q1, was primarily driven by flush production from the 20 wells we completed during the quarter. Total cash G&A declined by 13% to…

Thank you, George. Centennial added six rigs during the second quarter of 2017 and spud 20 wells. Centennial also completed 20 wells during the quarter, with the majority of these being drilled in the Wolfcamp upper and lower A. On average, these wells exceeded our internal expectations and continue to prove the high quality nature of Centennial's acreage position. As you will see on slide 5, we have delivered tremendous results that are second to none in Reeves County during the last few quarters. I will address a few of these standout wells completed during the second quarter. Turning to slide 7, the first two wells are located on Centennial's legacy acreage and have the highest IP 30 per lateral foot drilled to date by Centennial. The Stephens 2H was completed in the Wolfcamp upper A, with an effective lateral length of approximately 4,190 feet. The well had an IP 30 of 1,503 barrels of oil per day, and 1,953 barrels of oil equivalent per day, 78% of oil. This well generated an IP 60 of 1,365 barrels of oil per day, and 1,758 barrels of oil equivalent per day, again, 78% of oil. Another high performing well in our legacy acreage was the Russell 6H. This well was also drilled in the Wolfcamp Upper A with 4,185 feet of effective lateral lake. The IP 30 was 1,503 barrels of oil per day, and 1,750 barrels of oil equivalent per day, 86% oil. The IP 60 was 1,272 barrels of oil per day and 1,487 barrels of oil equivalent per day, again 86% oil. As you may remember, during the first quarter, we announced the Big Fundamental 4-52 1H, which at the time, ranked as one of the best wells drilled in Southern Delaware, in the Southern Reeves County on…

Thanks Sean. Now, I will provide some thoughts regarding the oil macro picture and relate them to the Centennial strategy. We expect total U.S. production to grow 425,000 barrels a day in 2017, and we see both U.S. and global inventories returning to normal levels, by March 2018. Like many others, we are surprised that current oil prices haven't yet responded more strongly to falling inventory levels, but we think prices will inevitably have to respond to tightening physical supply-demand signals. We think the big surprise will come in the 2019 and 2020 period, when total U.S. oil growth will be less than many people are currently predicting, because of the deterioration in the remaining number of tier-1 locations in the Eagle Ford and Bakken and declines in the Gulf of Mexico. Even in a robust oil price environment, I'd expect 2019 and 2020 total U.S. oil production growth to be 700,000 to 800,000 barrels per day per year, which is much less than the 1.5 million barrel per day, many people are predicting. Even likely, 2018 through 2020 global demand growth of 1.4 million barrel per day per year, this sets up a tight supply-demand picture. I would also caution people to be wary of extrapolating well level economics, that almost all E&Ps advertise into assumptions regarding ever expanding U.S. supply. Ask yourselves a simple question; if these advertised economics are so great, why has the industry destroyed so much capital and generated negligible GAAP income over the past three years? Centennial's base plan is to grow to 60,000 barrels of oil a day by 2020. However, if the short term oil price disappoints, we will consider lowering our 2018 oil and CapEx target, on the path towards 60,000 barrels a day in 2020. We don't intend to waste…

[Operator Instructions]. Our first question comes from the line of Will Green from Stephens.

Good morning everyone.

Good morning Will.

Appreciate the color that you just gave us on the long term guide. Just to kind of clarify, it does sound like you guys are expecting that prices to improve still. But in your remarks, if crude prices disappoint, and we should think about that as kind of a closer to $40 level, that's where you guys would start to think about ratcheting back that long term goal, is that fair?

You should consider our 2020 goal of 60,000 barrels a day intact. I mean, there is no change to that, whatsoever. The path -- and that's really based on our macro view, that by 2020, you know, we expect a WTI price in the range of $60 to $65. The path between today and 60,000 barrels a day, is going to be a function of how oil prices proceed. And so, we are going to just look at our view of what the oil macro is at year end this year, and then we will put out a number, as to what that path is going to be in 2018, en route to 60,000 barrels a day. And yeah frankly, if the oil price happens to be $40 at year end this year, that will be a disappointing oil price for us, and it's likely that we would scale back our trajectory towards 60,000 barrels a day in 2018, than what it otherwise would be.

I appreciate that. And then I wanted to ask on the northern Delaware, sizable position but not near as block E [ph] as you guys have down in the Southern Delaware. But realizing that is a great zip code, and obviously, you guys wouldn't be there if you didn't think so as well. What do you guys see as the limiting factors to ramping rig count ultimately in that area, is it infrastructure, is it just scalability of that asset, you know, where do you see that area -- how do you guys see that area evolving, in terms of the position of your portfolio, two to three years down the road?

Yeah. I mean, frankly, if I would grade our acreage, I would break our acreage into three tranches; the GMT, which is in Northern Delaware, the Silverback position, which was the first acquisition we made, and then our legacy Centennial position, which is how we started out. And if I would grade it on the quality of our acreage; number one, I'd say, all three are high quality, but if I put it on a relative scale, I would say, the GMT is probably the highest quality, the Silverback second highest, and the legacy Centennial was probably, I would grade as third in priority. We have made good wells on -- certainly on the Silverback and on the legacy acreage, as you can see from the slides we released yesterday afternoon, haven't drilled any wells on our own so far in GMT, but I expect that's going to turn out fine. So we are blessed with having three tranches of high quality acreage. But I would say that, if we can add acreage in Northern New Mexico at reasonable prices; reasonable would be in the $20,000 an acre range, as we added for GMT and for the Silverback, we will do it, but I'd also say that, adding to our position in Northern New Mexico or in the Northern Delaware, is not our highest priority right now. I feel like we are a big enough size, where if we can only add small increments in the Northern Delaware, I am still happy with the size of the company. So don't look for us to be aggressively chasing acreage in the Northern Delaware. When I say aggressively, going at $30,000, $40,000 an acre, just to say we have accreted a significant position. That's not going to be our game plan. So hopefully that gives you some clarification, Will.

Absolutely. Thanks for all the color and congrats on the early success.

Thank you.

Our next question comes from the line of Brian Corales with Howard Weil.

Good morning John.

Good morning Brian.

Just, you aren't adding a seventh rig, but the drilling and completion, number of wells isn't changing. Could you maybe try to quantify, can you used to be -- did you all estimate 10 wells per rig a year, is it now 12. Can you maybe try to quantify that a bit?

Yeah. Sean, you want to fill that question?

Yes. We were thinking of it as about 12 wells per rig, and we are upping that base on the efficiencies we have seen right now. We have completed our -- spud 20 wells during the quarter, and we also completed 20 wells during the quarter, and I will expect that cadence to continue for the remainder of the year.

Okay. And then, one, you all did a heck of a job on the unit costs. I think you had a clean sweep across the board. You know, is that more efficiency driven, or was a big portion just production a lot higher than you originally thought?

Yeah Brian -- I'd like to say, it's brilliant levels of efficiency. But I wouldn't have to say, that a significant portion of that is just the denominator, the production volumes. Yeah, we are increasing efficiency, but it's production volumes. This is the same phenomena that we saw at EOG. It's really growing the production volumes at a much higher rate than -- that really just dilutes the costs. And I think what we are going to see in 2018 and 2019 and really through 2020 is, that pretty much all of those unit costs are going to get driven down considerably more, just again, because the denominator, the volumes are going to go up so disproportionately fast. So what I would say is, what you are going to see -- what you saw this quarter, and what you are going to see in subsequent third and fourth quarters, is really just the start of how those unit costs are going to get driven down. Expect to see that to get amplified in 2018, 2019 and 2020.

All right guys. Thank you.

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

A question for Mark, and not to distract from an exceptional quarter, but there has been a lot of focus in our view, irrational fear or outright panic in the market about gas-oil ratios in the Permian. Just given your experience, really perhaps more on conventional oil wells than anyone, could you give us some high level observations on your experience regarding, how unconventional wells behave over time, as it relates to GOR?

Yeah. Sure Michael, I will be glad to. Yeah, this whole issue of 'bubble point death' is -- my view of it is that, and in my previous life at my previous company, we did a fair amount of research on this, particularly as it relates to the Eagle Ford, and I would say that, where you are dealing with a reservoir that has not been previously depleted by vertical wells, and that certainly would apply to the Eagle Ford, it would apply to the Bakken, it would apply to the Delaware basin, just with the big three shale plays. I'd say, this whole bubble point death issue is not relevant. Just simply, it's just not applicable. And so, my feeling -- and I am talking really as a reservoir engineer here, I don't think it's a factor at all. The only place where it might be a factor, would be in the Midland basin, where you got 70 years of Sprayberry depletion and also some Wolfcamp depletion, and I would just say, it's something that needs to be watched in the Midland basin, and it's just something that needs some further time and observation to see, if indeed it is a factor there, and that's where I would just leave it, at this point in time. But is it something that is undermining all shale plays in the United States, I would say, definitely no, that would be my overview statement to you.

Got it. I appreciate the color there. And then just, given the gains you guys are seeing on the productivity side, obviously, you changed the completion design. But just curious, how important is geo-steering to productivity in the scheme of things?

Again, going back to my previous life there, I would say, it's surprisingly important in there, in that -- one would think that, if you miss the optimum target by not being in zone for say 75% of a well as opposed to, say, 95% of a well, what does it matter, because you are just going to frac the heck out of it anyway. That would be just -- you think it just is an overview statement, that you overcome that with a frac. But the experience I had in my previous company, would contradict that strongly, and I'd say that, probably in order of priority, the frac optimization is clearly the single most important thing, picking the target zone, to make sure you have the right target zone is probably the secondmost important thing. And then the thirdmost important thing to making a good well, is then making sure that you get the thing geo-steered, where somewhere between 90% and 95% of your well, of the lateral, is in that target zone, and generally, that target zone is maybe a 20 foot target zone. So the geo-steering is, I'd say, one of the three primary things, and I'd say it's very important. You got to get those three things right; the frac, picking the right target interval, and then, getting the lateral to actually be in that target interval. So those would be the top three things to making an effective successful oil exploitation, shallow exploitation kind of a strategy, if you will.

Got it. Awesome color. Thanks Mark.

Okay, Michael.

Our next question comes from the line of Dan McSpirit from BMO Capital Markets.

Thank you, folks. Good morning. Following up on the ranking of the three operating areas, can you speak to the difference in the oil cut, say between the company's legacy leasehold and what was acquired in the Silverback transaction? And how does the cumulative oil production differ between the two areas over time, and maybe related to that, if you could just touch on the GOR difference between the companies Northern and Southern Delaware leasehold?

Yeah. And as far as the oil cut, yeah I will answer part of that, and then Sean, you may want to chime in on a part of it. But there is, if you break again, our assets into the three separate groupings if you will, our legacy acreage, which is kind of -- I will say our southern portion of our Reeves County holdings, and then, the Northern Delaware holdings, those are both pretty analogous and that those are, what I will call, in the phase window or the oil window, in that -- both of those areas would have an oil gravity of roughly about 45 degree API, and both of those have relatively low GORs, between 1,000 and 2,000 GORs. So those are, I guess to describe it into layman's terms, pretty non-gassy in there, and relatively high oil content. Then our other area, which is the Silverback area, is in the -- what we used to call kind of EOG, it is tilting more toward the combo phase window, and that the oil gravities on our Silverback are higher. They are about 49 degree API, so they are moving a bit toward the condensate window. You are still in the oil window, but you are moving toward the condensate window, and moving directionally toward a combo play. You are not in the combo play, but you are moving directionally toward that, and your GORs, your gas-oil ratios instead of being between 1 and 2000, they are closer to about 7,000. So it's a distinct -- you are in a different regime, if you will. So the reason that our oil mix was up a little bit relative to the first quarter oil mix versus the gas, was simply that we had a little bit of tilting toward our legacy drilling versus Silverback in the second quarter, and we expect that's going to continue -- the proportion will continue about the same, with a little bit of GMT contribution through the rest of the year. But I would say, as confused with or as separate from some of these bubble point issues that are going on in the Midland basin, what could happen for example, if we get into 2018, if we decide to drill disproportionately on the Silverback acreage, we could end up with higher gas-oil ratios in 2018 into our mix, but that's got nothing to do with the bubble point, it's just that we are drilling more with a combo portion of our acreage, if you will. So I don't know, does that give you some explanation Dan, because we do have two separate phase windows on our acreage, if you will.

It really does, and I am thankful for it Mark, I am. And maybe just as a follow-up to that, you speak about the strength of your technical team, and that strength certainly shows in the reported results. What is it that's different, or even proprietary about the team's process, that makes for better wells, and how many of those folks have EOG in their pedigree?

Yeah. I would say, that the technical team we have assembled, you probably are looking at probably 50%, maybe 60% of that technical team, has EOG in their pedigree, either EOG directly or EOG once removed. And the system we have put in place, is very heavily influenced by the system I put in place at EOG. So it's very much a clone of that. And so, obviously at EOG, I still consider them to be probably the technical -- definitely, the technical leader in shale oil exploitation, and our aspiration at Centennial is to be the midcap technical leader in shale oil exploitation, not the overall industry technical leader. And what we are really doing is just, using that template that I put in place at EOG, and just replicating that template here at Centennial, and you are seeing the results of that template. And it's really a bottoms-up focus on technical underpinnings of every part of the business, and that's probably the simplest explanation I can give you there Dan.

I really appreciate it. And thanks again for the answers and have a great day. Thank you.

Thank you.

Our next question comes from the line of Jeanine Wai from Citigroup.

Hi. Good morning everyone.

Hey Jeanine.

Maybe just trying to get a little more detail around your comments on $49 flat oil and activity. I am focusing more on the near term. On the production guidance range, Centennial already is now growing 250% year-over-year versus 205% previously, and that's already top tier. Can you talk about how you think about balancing activity with the wide cash flow outspend this year, given that you are already ahead of your original production forecast? Based on our estimates, you guys don't come close to any of your financial [indiscernible], liquidity is fine, but what do you consider sufficient growth to achieve your corporate objective of having the best equity performance in the midcap space, especially since currently, growth is coming at a cost with above average outspend this year and potentially again next year?

Yeah. I mean, that's a good question, it's also kind of a subjective question. And I guess, I'd go back to saying, when we designed Centennial, we were able to start with a blank sheet of paper, and one of the parameters that I put on that blank sheet of paper to design Centennial was, I wanted to start the company out with essentially zero debt, and effectively, we started out with mildly negative net debt. And the reason I did that was, I said, I feel very strongly that a $40 or $50 WTI oil price is not a steady state long term global oil price, and that that is just too low. And I still believe that, and all you have to do is, look at the fact that nobody is making any GAAP net income, essentially, at the current oil prices or look at -- nobody is really making a full cycle, positive IRRs of any consequence at current oil prices. And so, it's my belief that a more stable, long term global oil price is $60, $65, and so I said, I want to design a company, that we can withstand several years of low oil prices, until we get to a more rational long term oil price. And to do that, we have to have a company that's not over-levered to start with. So we have an advantage over most every other company and that we have essentially no kind of leverage. And so, we are capable of outspending our cash flow for several years. In fact, one model would show all of that, if oil prices were just flatlined at $49 through 2020 and we decided to continue to go to 60,000 barrels a day and outspend cash flow through 2020, we get to a debt-to-EBITDA of somewhere like, take a 1.4 ratio roughly. So it's still not that high, the debt level. So we are continuing to go on the basis that, ultimately, oil prices will increase and we would just govern our path to 60,000 barrels a day, depending on what we view the macro on a year-to-year basis is. So it all goes back to us designing the company, to start with zero debt. So, hopefully, that gives you a little bit of our overriding thinking. But the overriding thinking is, is that ultimately, oil prices will go up Jeanine, and we want to be positioned, when they go up.

Okay. Thanks.

Okay. Thank you.

Thank you.

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

Hey, good morning. Really tremendous quarter. And my question has to do with the third Bone carbonate and the shale within the third Bone. Kind of curious, how extensive this zone is and roughly, where it is located, the new well you are going to drill? And then potentially, how many more new locations this could lead to, and if I might, a second question is on your 13-day well that you have done, one mile lateral in Reeves County, how much is that, in terms of total drilling completion cost at this drilling rate?

Yeah, Sean, do you want to fill that?

Sure. So first addressing the Bone Spring; the Bone Spring is present across our entire Reeves County position. So if we find that it's productive, it's going to add significant inventory to our current inventory, which is already at greater than 10 plus years. So I think that we are excited about that. We will be drilling a well here later this month, and have that online, hopefully by end of the year, and then we have identified multiple zones within the Bone Springs, and not just the third Bone carbonate looks productive, but some of the second Bone looks interesting as well. We have done a fair amount of work, looking at the lithology, from doing petrophysics and doing certain pressure tests to feel pretty confident that we are going to get some kind of production out of the Bone Spring, and hope that we can make it a commercial reservoir. The second part of your question was about the drill time, and efficiencies driven by that. We have seen about a 10% reduction in costs on drilling. So that's late 2016 to current. I think that we are doing great in that regard, and we continue to push that. As I said, in the initial part of the call, our last several wells that are averaging 15 days, and if we can continue to drive those down, we are going to continue to see increased cost efficiencies there.

Great. Would you be able to tell me where your new third Bone well will be located, roughly, on your acreage?

I don't think we are ready to disclose that yet.

Okay, thank you.

Our final question comes from the line of Derrick Whitfield from Stifel.

Good morning guys and great update.

Good morning Derrick.

Mark, bigger picture question for you, if you were to think about your 2020 game plan, how many rigs would you need to accomplish it, in light of your efficiencies in current well performance? And the point being, you are clearly doing more with less, but how much less to reach that objective?

Yeah, that's a good question. The original plan was, we would need to get up to somewhere around 12 or so rigs, by 2020. But my guess is, I mean -- my guess is that, with the drilling efficiencies and then the better wells that we are almost certain to be doing, we are probably going to end up -- kind of achieve that goal with somewhere in the range of probably 10 rigs. That's just a guess at this time Derek, so don't hold me to that. But it's probably going to be less rigs, and we had articulated a year ago. A year ago, we had articulated a schedule, that is probably -- it was an overstatement of how many rigs would be required to get to 60,000 barrels a day. And I'd just say, on the 60,000 barrels a day, we could flex that higher, we could flex that lower. That's a number that we can move in either direction, but we have got the well capability to go any which way there. But I'd say, for modeling purposes, you ought to use 60,000 barrels a day in 2020.

Got it. Thank you. And then one last question, in light of what you know today on the Russell 6H and Stephens 2H relative to the big fundamental, are you confident that 2,600 pounds per flow is the upper boundary on profit [indiscernible]?

We are kind of leveling off at that point. So don't look for us folks to be going massively to 3,000, and 3,500 or so. The way I'd view where we'd stand on kind of frac technology, at this particular point in time is, we have made great strides -- we are probably at the fourth grade level, six months ago, and today, we are kind of at the 11th grade level, and I'd say the best company out there is maybe at the 12th grade level today. So we are pretty much where we need to be, and turning the big dials, and now we are turning just the little dials on our optimization. So don't look for us to massively increase the profit loading, in terms of we are now at pretty close to 100% slick water usage, which is pretty much where we will be. I don't think we are going to change that too much. We may tweak some things on cluster spacing, we may tweak some things on types of perforating. But the way to view this is in the first six and in most recent six months, we have done a lot of changing on the big dials on frac optimization, and most of that has been done, and now we are going to be tweaking some of the smaller dials.

Got it. Thanks. Great update guys.

Okay. Thank you.

This is the end of Q&A for today. I will now hand the call back over to Mark Papa, for any closing remarks.

Okay. Thank you very much for taking the time to listen to us. The last thing I would just leave with you, is that, Centennial closed the Silverback acquisition at year end. So effectively, we got that thing closed on December 28th. So what I would say is, we have effectively been a company for about seven months. And if you view us in the context of the continuum of time, we have made tremendous progress as a company in seven months. And I now feel, that we are coming together as a company, we are beginning to gel. We have our team in place, and I think this particular earnings call was a manifestation of -- it's the first call, when you can view us as a company, where we got a team in place, and you are now seeing results of that team. So thank you for taking the time to listen to us.

This is the end of today's call. You may now disconnect and have a great day.