Good morning and welcome to Centennial Resource Development's Conference Call to discuss its Fourth Quarter and Full Year 2019 Earnings. Today's call is being recorded. A replay of the call will be accessible until March 10th, 2020 by dialing 855-859-2056 and entering the conference ID number 7679910 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.

Thank you, Rebecca. And thank you all for joining us on the company's fourth quarter and full year 2019 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 24th, we filed a Form 8-K with an earnings release reporting full year 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 statements section of our filings with the SEC including our annual report on Form 10-K for the year ended 2019 which was also filed with the SEC yesterday.Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.We may also refer to non-GAAP financial measures that help facilitate comparisons across periods and with our peers. For any non-GAAP measure, we use a reconciliation to the nearest corresponding GAAP measure can be found in the earnings release or presentation which are both available on our website.And with that, I'll now turn the call over to Mr. Mark Papa, Chairman and CEO.

Thanks Hays. Good morning and welcome to Centennial's fourth quarter earnings call. Our presentation sequence on this call will be as follows; George will first discuss our quarterly and full year financial results the monetization of our saltwater disposal assets and 2020 guidance. Sean will then provide an operational update including recent efficiencies well results and year-end reserves. And then I'll follow with my macro view, our current strategy emanating from the macro, and management's succession plans.Now, I'll ask George to review our financial results.

Thank you, Mark. Centennial finished 2019 with strong fourth quarter results. As you can reference on slide 19 of the earnings presentation, net oil production for the fourth quarter averaged approximately 45,000 barrels per day which was up 13% over the prior year period and 7% over Q3. Average net oil equivalent production totaled 79,734 barrels per day which was up approximately 15% and 4% above the prior year period and Q3 respectively.Revenues totaled approximately $256 million which was a 12% increase compared to Q3 primarily as a result of higher production and price realizations. Excluding the impact of basis hedges, Centennial's realized oil price was $53.25 per barrel for the quarter compared to $51.71 in Q3.Shifting to unit costs, on the last earnings call, we identified several initiatives to mitigate the increase in lease operating expense incurred during Q3. The preliminary results of those initiatives have been positive. LOE per barrel decreased by 12% from Q3 to $5.30 per barrel primarily as a result of reductions in equipment rental, electricity, chemical, and labor costs.Cash G&A for Q4 was $2.12 per barrel which was up quarter-over-quarter primarily as a result of a non-recurring contract settlement charge. Without this one-time charge, cash G&A per barrel would have been $1.88. DD&A increased by 4% to $16.75 per barrel and lastly GP&T expense decreased 5% to $2.82 per barrel. For the quarter, we recorded GAAP net income attributable to our Class A common stock of $9.6 million. Adjusted EBITDAX totaled $160 million, up approximately 20% from Q3, due to higher revenues and lower LOE.Shifting to CapEx. During Q4, we ran five rigs compared to six rigs for most of Q3. For the quarter, we spud 22 gross wells and completed 27 compared to 21 gross wells in 2017 respectively during the prior quarter.…

Thank you, George. This was another consistent quarter of strong execution for Centennial. As we highlighted last quarter, our operations team continues to do a tremendous job driving down well costs as a result of efficiencies gained in the field.As seen on slide 7, we've been able to reduce our spud to rig release in the fourth quarter by almost 40% to 19 days on average compared to last year. Importantly, we were able to achieve this, while remaining inside of our 30-foot target window, 95% of the time during the entirety of 2019.Similarly on the completion side, we've increased our average stages pumped per day during the quarter by 30% year-over-year to 6.4 stages per day. Overall these efforts resulted in an over 20% reduction in fourth quarter well cost for our 7500-foot laterals compared to the prior year period.Combined with longer laterals and larger pad size, this has translated into a material improvement in our overall capital efficiency. Importantly, we believe there are additional efficiencies to be gained and this will be a primary point of focus for CDEV in 2020.Now turning to results for the quarter on slide 8, in Reeves County, the Bodacious 2-well pad was drilled using approximately 6200-foot laterals in a staggered pattern targeting the Third Bone Spring Sand and Wolfcamp Upper A intervals. The pad delivered an average IP-30 of approximately 1800 barrels of oil equivalent per day or 210 barrels of oil per 1000-foot of lateral per well.Overall Centennial completed 10 Third Bone Spring Sand wells in Texas during 2019 with the majority of them being paired with a Wolfcamp Upper A. We have not only proven the viability of co-developing these two zones, but most importantly our Third Bone Spring Sand results to date have been on par with our Wolfcamp…

Thanks, Sean. Now, I'll provide some thoughts regarding the oil macro picture and relate them to Centennial's 2020 strategy. I'll also discuss our management succession. Two things are apparent regarding the 2020 global oil supply-demand picture.First, U.S. oil year-over-year growth will be less than past years. And second, global demand will likely be less than one million barrels per day this year. CDEV's 2020 business plan response to the current Coronavirus-induced low oil price is simple. We're prioritizing balance sheet preservation over production growth. Our CapEx budget is approximately 30% lower than last year. Again, we still expect to achieve a small amount of production growth. We believe the slowdown in overall U.S. production growth will allow the global market to rebalance within a reasonable time frame and we plan to preserve our balance sheet until that occurs.By monetizing our saltwater disposal system and reducing from a five to a four rig drilling program we expect to be essentially cash flow neutral this year based on the current forward strip. I'll remind everyone that we have 80,000 reasonably contiguous acres in the heart of arguably the best U.S. shale oil basin that we're one of the few companies with a multiyear track record of exceeding our production target, while staying within our original CapEx estimate each year.I'll also note that, unlike many other shale companies CDEV has not had any spacing or well pattern debacles. From the get-go, we've spaced our Texas wells at a conservative 880 feet. When you aggregate acreage quality, operational execution, a clean balance sheet, and good management that's a strong combination.Speaking of management, I think all of you have seen our press release announcing our management changes that will take place June 1. I'll be retiring and Steve Shapiro, will replace me as nonexecutive Chairman;…

Thank you. [Operator Instructions] And your first question comes from the line of Matt Portillo with TPH.

Good morning, guys.

Good morning, Matt.

Just a strategic question from a capital allocation perspective. Investors are looking for industry participants to move towards capital allocation strategies that are able to generate free cash flow under strip pricing. For 2020, you backstopped the outspend with the saltwater disposal. But as we look out into 2021 and beyond, if crude remains depressed at these $50 levels, should we expect a further paring back of capital towards a cash neutral program?

Yeah. In 2021 if crude remains at $50, I think it's pretty well. Certain it will prioritize the balance sheet again over production growth. And that I think is very, very likely. It'd be really, really odd to say in that kind of environment that CDEV would say, we're going to grow production in a $50 or $52 oil environment.Again, that would go back to the macro picture that I've articulated. I think that we're going to see a significant slowdown in U.S. production growth this year. I'd say that's certain to happen if you play that out in 2021 and you say you're at the $50 or $52 oil price environment. I'd go so far to say that the U.S. year-over-year production growth in 2021 would probably be zero under that price environment. So, one would expect a significant tightening in global supply demand.So, I don't think you could go too many years with U.S. year-over-year production growth of zero before you'd see a rise in oil prices. So that would be the thesis that we would work under that we would preserve the balance sheet at CDEV, and that with a significant slowing in U.S. year-over-year production growth that there wouldn't be too many years before you would see an increase in global oil prices.

Thank you. That's very helpful. And as my second question, just curious if you could dig a little bit into the facility spend as it relates to 2020? Any incremental color you could provide on where that capital -- the $105 million of capital is going towards? And then just a bigger picture question over time, how should we think about that facility spend as the asset starts to mature and as you start to spend more and more capital at the drill bit?

Yes. Sean, do you want to field that?

You bet. Thanks for asking the question Matt. So, as we talked about it's pretty material decrease in facilities and infrastructure spend year-over-year. So, we're certainly seeing the benefit of maturing the asset.On the facility side, those allocated costs are really at the wellhead so that includes tank batteries and things like that what's needed to hook up to the well. We do think we're seeing some incremental savings there by going back into re-existing facilities and utilizing what was there from last year and years prior. So, we're seeing some nice efficiencies gaining there.On the infrastructure side as -- we're still a young asset if you will. But as we developed this over the previous several years, we've been able to spend enough infrastructure to where the position is pretty well set up. So on an annual basis, there is a nice reduction in infrastructure spend from 2019 to 2020.We do have a few items that are outstanding that include, as we've talked about in previous calls, our electrical substation still needs to go live. A portion of that was spent last year, but the remaining portion will be spent in 2020. And then the second part of that is there's a little bit of infrastructure that needs to be spent in New Mexico to bring that up to where we needed to be before full development. So, that's where the lion's share of the infrastructure spend is for 2020.

Thank you.

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

Yeah, thanks. And first congrats Mark on your long and successful career. Your leadership I think point on has been an asset to the industry and hope you well in your future endeavors.

Thanks, Scott.

You bet. My first question is -- and maybe Mark you want to start out. Certainly, George, you want to sell then late -- them after, but you talked about your view on the macro and how CDEV would potentially look to develop its assets moving forward in this environment? And you did talk about maybe a point at which the market gets more balanced. Can you give us a view on when you think that occurs? And bigger picture has your view on hedging oil change given what's happened over the last couple of years?

Yeah. On the macro situation there Scott, it would seem like to me that absent the coronavirus, we were on the verge of being balanced sometime in the second half of this year where we were likely to see $65 WTI in the second half of this year. Now you lay the coronavirus on there and I think it's probably pushed the balance situation into likely 2021 in my view.And so what I think we're going to see happen is U.S. year-over-year production growth is going to slow down considerably from the 1.2 million barrels a day that we saw in 2019 to probably 400,000 maybe 500,000 600,000 barrels a day this year and then likely considerably less than that in 2021 and 2022. And so I think we're going to see a balancing in 2021 or no later than 2022 as we see a structural change in the ability of total U.S. production to grow short of oil going to $80 and stabilizing there which I don't think any of us believe is all that likely.So playing into CDEV strategy, the strategy is pretty simple. It's preserved the balance sheet as we watch U.S. production growth year-over-year frankly weaken over the next 12 to 36 months – permanently weaken let me say. And have CDEV in a position where we have significant inventory at that time and a strong balance sheet at that time and we're located in arguably the best U.S. oil shale basin, where we can then grow significantly and have the ability to add some additional acreage during this weak period and be a small company but a small high-growth company when we see the pricing signals go that way.So that simply put is our strategy. And whether that period is 12 months or 24 months, I can't tell you but I don't think it's going to be much longer than 24 months over a period of these low oil prices. So hopefully that answers your question.

Yes it does. Good. And just about the hedging then. Has your hedging views changed?

The hedging, since we can't tell exactly when this is going to turn around it's not – I'd say at least at this period in time it's probably not a good time to hedge oil. So I don't think we'll be hedging any oil at least during my tenure which is not that long. So you can see how Sean wants to play that. I mean that strategy may change after I leave. I've been a notorious anti-hedger. Maybe that's been a good move maybe that's not been a good move but that's one philosophy that might well change as I transition away from the organization.

Right. Is it too early – it puts you on the spot on that one or should we save that one for the second quarter conference call?

I'd probably say that for the May conference call Scott. Yes, okay.

Fair enough. And my follow-up question. Your 24 completions in the quarter was extremely robust relative to what – I think you only can model in what you're expecting but we'll play the role in that. Was it doubts you had? Was it the size of well pads that you had coming online or timing of those? Can you give a little color on what caused such a high completion come in 4Q?

Yes. Sean?

Sure. Yes thanks for the question. It certainly wasn't DUCs. We don't have a practice of building up DUC inventory haven't in the past and that's certainly not something that we look to. Obviously, when you're doing pad development, there's just some lumpiness that comes along with that. So we had a fewer completions in Q3 versus Q4, really related to just the pad timing of when wells were being completed and brought online. So nothing strategically positioned there. It was really just a timing thing.

Understood. Thanks.

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

Thanks. Good morning. Mark all the best on your retirement. Your views will be missed. And Sean congrats on the new role. Sean on slide 6, you talked about DC&F CapEx per completed foot that was down nicely in 2019. What does the 2020 budget imply? Because in your prepared remarks you talked about long lateral and larger pad size. Any thoughts on 2020 lateral length or pad size would be appreciated?

Sure yeah. Thanks for the question and I'm pointing that out again. I think slide 6 is a great representation of a pride if you will from the operations side of things where we reduced well cost pretty significantly from what we thought we were going to accomplish beginning of the year to where we ended up at the end of the year.I think if you roll that forward that's a good view of how we have guided our 2020 look forward at D&C costs on a per foot basis maybe just kind of split the difference there I think it's a decent way of looking at what we've got going forward. That's driven by a combination of things. Obviously pad size, reuse of existing facilities and then really the operations team continuing to drive efficiencies in the field. And the majority of that drive is really working with our technical team. Obviously we've done some things with bottom-hole assemblies and mud systems and whatnot. I think that's been effective. But really working with the technical teams, geology, reservoir engineering et cetera has really helped us to identify any drilling hazards and avoid those as we're going.And I think that we've shown that we've been able to drive efficiencies pretty materially year-over-year. Going forward, I do think there is some more opportunity to lower those costs throughout 2020. But until we execute on those none of that's baked into our 2020 guidance.

Got it. Sean, thanks. And George, a quick one for you. Thanks for the update on infrastructure spend. Can you discuss a good rule of thumb to estimate recurring infrastructure spend beyond 2020 post water disposal and post the electric substation spend?

Yeah. The challenging thing there is -- there does tend to be a little bit more lumpiness on the infrastructure side relative to facilities. So, I said it's frankly difficult to give you a good number on that. I think I had referenced on last quarter's call that the relative split of facilities and infrastructure was approximately 75% -- 25% historically. And I think that's generally a good rule of thumb going forward.Although I would say on monetizing the SWD system will obviously lower that requirement on a go-forward basis. In 2020, we have the power substation, which is adding some incremental CapEx cost. So it's really tough to predict, but I do think over time those costs are going to continue to come down.

Appreciate. Thank you.

Your next question comes from the line of Kashy Harrison with Simmons Energy.

Good morning and thank you for taking my question. So my first one just looking through the K, it looks like there was a section where you talked about acquiring about 24,000 net acres in the Permian Basin. Was just wondering, if you could share any additional color on what that pertains to? And then also it looks like there was about $84 million of proved -- unproved property acquisitions. I was just wondering what all that was related to? Thank you.

Yeah. On the first -- I'll field the first part of that. And I don't know George or someone you might want to check on the second part of that one. I'm fielding the first part of that question. So you did your homework looking at the K on there Kashy. Good job. Yeah, the acreage that's mentioned in the K is something that -- if you know my track record EOG, we don't like to stand still on our existing plays and what I'll just answer in circuitous manner is that we're consistently looking for exploration plays. That acreage relates to a new exploration play somewhere in the Permian Basin. And for confidentiality reasons, we're still working on acquiring acreage in that particular play. We'll be drilling it and testing it sometime in the first half of this year. And that's all the information I'm prepared to disclose at this time relating to that. So for the second half of it, George, you want to field -- see if you can field that particular question?

Sure, Kashy. I don't have the K in front of me. But, I think, part of what you're describing will include some of the activities Mark just mentioned, but also some smallish organic leasing and acquisitions we've done throughout the course of last year. So nothing -- no one driver that kind of drove the number, but a compilation of different things.

Got it. That's helpful. Thanks for the comments on both fronts. And then, there was a comment, I think, in the release that most of the spending -- most of the D&C spending in 2020 would be on operated as opposed to non-op. I was just curious, in 2019, what percentage of D&C was allocated to non-op? And how does that track entering 2020?

I think, Kashy, for 2019 it was less than 5%. And I think we're taking a consistent view with that for 2020.

Awesome. Thanks for that. And Mark, best of luck in retirement.

Thanks, Kashy.

The next question comes from the line of Neal Dingmann with SunTrust.

Yes. And congrats on the new position. My first question centers on your slide nine on the Southern Delaware results. I'm just wondering here, do you all envision doing more of these multi-zone pads such as the Bodacious or will sort of more the focus on this year target multiple -- some of the pads such as the Lucy Prewit, where you're just targeting multiple wells in one formation?

Sure. Yes, thanks for the question. I think that, going forward, it will be a combination of both of those. But I think that, what we've shown is that, doing multiple reservoirs in New Mexico off of a single pad is definitely successful. And it allows us to develop the asset in the most efficient way. So, certainly, that will be a large portion of our development going forward.

Okay. My second question just follow-up on what George has talked about -- a little bit on acreage, given the slow in activity, is there any issues on holding existing acreage? Or is that maybe part of what the $10 million to $20 million land CapEx is directed towards? Or is it most of that HBP?

Mark, I'll take that one. So, we do have a small portion of our land budget that goes to making sure that we can retain our position together. But the majority of our acreage is held with the rigs. And so, I think, that the combination of the two will allow us to keep our position together in 2020 and beyond.

Great. Thanks, Sean.

Thank you.

Your next question comes from the line of Will Thompson with Barclays.

Hey, good morning. Mark, congrats on your re-retirement and congrats to Sean and Matt on the promotions. Maybe for Sean or George, maybe you can help us understand the potential production cadence through 2020? You're coming off a strong 4Q with 27 completions, you'll be carrying a fifth rig through April.How does that set up for one half versus second half? And then, it was mentioned in the prepared comments that CDEV still targets a moderate oil growth at four rigs. What would that reasonably can be for oil growth in 2021? And I know it's a tough question, but maybe any color you can provide would be helpful.

Sure. Yes, I think, it is a tough question. But, I think, we're dropping a rig at the end of the first quarter. And so, the balance of the year, we'll be running a four-rig program. So there will be a little bit of lumpiness. Obviously, we don't give quarterly guidance. We give annual guidance. But first quarter, I think, you can assume is going to be our highest capital quarter, because we have an extra rig running. And I think from a production point of view, you'll see the effects of that in Q2, but then you'll also see what we are forecasting for the midpoint of our production for the year. So I think you can make some generalized assumptions from that statement.

Okay. Thank you. And then the 10-K shows about $1.6 billion or about $20,000 per flowing barrel PDP, PV-10 at 52 -- around 52 WTI. With that my math indicates your current enterprise value implies less than $3,000 per net acre. Would you consider selling some acreage that's in the back part of your inventory stack to further offset outspend? Just curious on any thoughts there?

Yeah. Will, I'll field that question. Likely, no. I mean, we -- not any significant acreage to cover any outspend at this point. We've got our acreage pretty well caught up and we sold a little bit of acreage that was on our Western fringe during 2019. And so right now, I'd say that the acreage we have, which is just a tad less than 80,000 acres is pretty much 100% core. So at this juncture, it's unlikely we'll be selling any acreage in either Lea County or Reeves County of any consequence. And we're not looking at the option of using acreage sales to try and equilibrate to cash flow neutrality.

Okay. Thanks for taking my questions.

Okay.

Our next question comes from the line of Leo Mariani with KeyBanc.

Hey, guys. Wanted to kind of follow-up a little bit on some of the macro thoughts and comments Mark that you articulated a hopeful rise in oil prices in 2021. Just wanted to get a sense of whether or not there's flexibility in 2020? If we were to get an oil price recovery say in the second half of 2020, my CDEV considering -- consider adding another rig? Or would you just kind of stay put with the existing four rigs here?

Well, we've -- I mean, we certainly have the flexibility. I mean, there's certainly going to be rigs available to be picked up. And if you look at some of the third-party forecasts, there are forecasts out there that are forecasting by the fourth quarter WTI will be $65 a barrel. So where that to occur, where that tightening to occur, I'd say that we would certainly consider adding back a rig.But at this -- and so, I'd say, at this juncture, we expect to see the tightening in 2021 and probably the most likely scenario would be that we would continue with the program we've articulated through 2020, and then if indeed we see the tightening and oil prices firming that it's possible we consider adding back that rig in 2021, as opposed to making a change to our capital program in 2020. That's the most likely scenario kind of. Even if oil prices firmed up in late 2020 we'd probably stand pat until 2021 and then make a change in 2021.

Okay. That's helpful color in terms of the thinking over there, for sure. Just a question on the cash G&A guidance, you guys came in, just over $1.80 per Boe, in 2019. I think you guys are saying that could go up, to say, $2 to $2.30, in 2020 here.So you're kind of moving up a little bit, on a per-barrel basis. Just wanted to get a sense of what might be driving that? I guess I would have thought maybe with less, rigs that G&A really wouldn't be going up here, in 2020?

Yeah, George?

Sure. I think we did a very modest amount of hiring, during the course, of 2019. So I think there's a little bit of increased cost associated with that. But we are very well staffed for current levels.And I think if you factor in at least for Q4, that there was roughly a $2 million contract settlement charge in our G&A. There's a bit of an offset to Q4 there. But if you step back and look at our dollar per Boe, which at the midpoint we're saying for 2020 is $2.15, that still rates very well relative to the small and mid cap peers out there on a dollar per Boe basis.We are very much towards the lower end of that metric. I think philosophically we tend to run very lean and efficiently. So while we are seeing a little bit of increases, relative to where we've been historically, I think overall the company is very well placed, from a cost standpoint, on G&A.

Okay. That's helpful color. And I guess maybe just on the D&C and F, well cost per lateral foot, were the main drivers that caused the big reduction, which I think you guys said was primarily in the second half of 2019, to get that big year-over-year reduction?

Sure. I'll field that one. I think that it was kind of a couple of things. Obviously, service costs came down a little bit at -- in the middle half of last year. But that was a portion of it.The greater portion of it was really the efficiencies that we're seeing in the field. I think, we've just had that much more experience and repetition now out, in our portion of the Delaware Basin to where we understand what it takes to get these wells down. That in combination, as I said earlier, with our technical teams identifying any potential drilling hazards, when you can avoid those, you reduce your days of drilling and completions.And so, the combination of all that has allowed us to be that much more efficient, in our D&C cost.

Thank you.

Great, thanks, Leo. Rebecca, do we have any more questions in the Q&A?

There are no further questions.

Well great. Well at this time, everybody can disconnect. I'd like to thank everybody for their interest in Centennial. And feel free to reach out with any questions. Thanks a lot. Have a great day.

Thank you for participating. You may disconnect, at this time.