Good morning, and welcome to the Centennial Resource Development's conference call to discuss its third quarter 2020 earnings. Today's call is being recorded. A replay of the call will be accessible until November 17, 2020, by dialing 855-859-2056 and entering the conference ID number 3692456 or by visiting Centennial's website at www.cdevinc.com. At this time, I will turn the call over to Mr. Hays Mabry, Centennial's Director of Investor Relations, for some opening remarks. Please go ahead, sir.

Thank you, Rens. And thank you all for joining us on the company's third quarter call. Presenting on the call today are Sean Smith, our Chief Executive Officer; George Glyphis, our Chief Financial Officer; and Matt Garrison, our Chief Operating Officer. Yesterday, November 2, we filed a Form 8-K with an earnings release, reporting third quarter earnings results for the company and our operational -- sorry, 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 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 sections of our filings with the Securities and Exchange Commission, including our quarterly report on Form 10-Q for the quarter ended 9/30, which will be filed with the SEC later this afternoon. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially. We may also refer to non-GAAP financial measures that help facilitate comparisons across periods and with our peers. For any non-GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation, which are both available on our website. And with that, I'll turn the call over to Sean Smith, our CEO.

Thanks, Hays. Good morning, and welcome to Centennial's third quarter earnings call. On today's call, George will first discuss our quarterly financial results, liquidity and updated guidance. Matt will then provide an operational update, including recent operational initiatives, well results and updated D&C costs. And then I'll follow-up with a quick recap of the third quarter capital efficiency gains to date and provide a high-level overview of 2021. But before I hand the call over to George, I wanted to point out that what you will hear today stems from our new corporate slogan, Centennial 2.0, which centers around heightened capital efficiency and the goal of generating sustainable free cash flow. In the following discussion and within the presentation materials, you will see the significant progress we've made towards these goals in a very short period of time. With that said, I'll turn it over to George to review our financial results.

Thank you, Sean. Turning to our financials on Slide 17 of the earnings presentation. Net oil production for the third quarter averaged approximately 35,300 barrels per day, which was down 16% over the prior year period and represents a 6% decline from Q2. Supported by the 5 wells brought online during August and a reduction in production downtime, Q3 oil production volumes exceeded our expectations. Average net oil equivalent production totaled approximately 68,900 barrels per day, which was down 10% from the prior year period and represents a 1% increase from Q2. The relatively flat sequential equivalent production volumes were primarily driven by an increase in gas capture, a full quarter of ethane recovery and less flush oil production from new wells compared to previous periods. Revenues totaled approximately $149 million, which was a 65% increase compared to Q2, primarily as a result of higher price realizations across all 3 product streams as well as higher NGL and gas production. Excluding the impact of commodity hedges, Centennial's Q3 oil realizations were 90% of WTI or $36.95 per barrel compared to $21.47 in Q2. NGL prices were up 63% to $12.58 per barrel compared to Q2. Turning to costs. Unit costs continue to look very strong relative to our expectations. LOE per barrel decreased by 7% from Q2 to $3.87, primarily as a result of a continued reduction in equipment rentals and electricity costs. Matt will provide further details on LOE shortly, but we are seeing very tangible progress on our cost reduction initiatives. Cash G&A for Q3 was $1.94 per barrel, which was down from $2.21 during Q2. DD&A decreased by 6% to $14.10 per barrel relative to Q2 because of upward PDP revisions and lower D&C costs. Lastly, GP&T expense increased 9% quarter-over-quarter to $3.02 per barrel, in part…

Thank you, George. Today, we are happy to report our fourth consecutive quarter of reduced LOE, the completion of 5 DUCs in New Mexico and a return to drilling operations. As this challenging and transformative year enters its final months, it's truly amazing how far this team has come. Today, I'll cover several ongoing initiatives centered around improvements in LOE, DC&F costs and flaring. As noted on Slide 6, our focus on margin expansion can really be seen. Third quarter LOE came in at $3.87, representing a 36% year-over-year and 7% quarter-over-quarter decrease. This fourth consecutive quarterly drop is the result of ongoing initiatives in the field that we mentioned in the last earnings call. This quarter, we saw the electrification of Phase 2 of our substation in Reeves County. Effectively, our Reeves County substation, detailed on Slide 7, has reduced our generator count from around 125 in Q3 of 2019 to around 30 in Q3 2020. And by year-end, with the third phase of our field electrification completed, we hope to see that number of generators drop to roughly 10. This transition to line power impacts our business in several ways. We've seen significant reductions in rental costs, fuel costs and downtime at the well site level. The line power source is much more reliable, and that directly impacts the bottom line by fundamentally changing our run rate assumptions on downtime. The profitability of this project can easily be understood, but we at Centennial are also compelled to be good stewards of the land on which we operate. The transition away from generator power means there will be over 100 fewer combustion engines running in the field. And while recently touring our field operations, the enthusiasm from our team members around this project as well as additional opportunities to…

Thanks, Matt. So let's quickly recap what we've achieved this quarter, which is outlined on Slide 14. On the left-hand side, you can see our key initiatives, which were taken verbatim from our Q2 slide deck published in August. On the right-hand side, we've listed our actual results from the quarter. And as you can see, we've either met or exceeded every goal that we've set out to accomplish. Starting with LOE, we reduced our per unit cost 36% through the execution of field level projects and, as a result, removed over $2 from our unit cost structure. Additionally, we lowered our all-in D&C well cost target by 11% as a result of higher efficiencies and structural design changes. In early October, we received affirmation of our borrowing base and organically increased our liquidity position by paying down debt during the quarter. Furthermore, to help protect cash flow from any deterioration in commodity prices, we added approximately 5,500 barrels a day of incremental oil hedges in 2021, primarily targeting the first and second quarters. Lastly, we were able to execute on all of these objectives while efficiently returning to operational activity during the quarter. Overall, this was a strong quarter for Centennial, and I'm very confident that the recent changes made to our cost structure are more permanent in nature, providing the company with a solid foundation going forward. To further build upon this statement and how it affects the underlying business, I'd like to shift to Slide 5, which shows the rate of change of Centennial's capital efficiency on certain key metrics. To start, our development program is now underpinned by significantly lower well costs as our current target represents a 40% reduction from last year. Next, we are resuming activity with a much shallower corporate decline rate. We…

[Operator Instructions] You have your first question from the line of Scott Hanold.

Sean, that was good color on what 2021 might look like, because I think that's obviously what a lot of folks are focusing on at this point. Then if you were to run a maintenance program and looking at the current strip, can you give a sense of what that -- does that get you to a near free cash flow neutral position? Or what's your tolerance to our ability to outspend? And on that maintenance program, if you can give us an idea of like how many wells does that contemplate being brought on.

Sure, Scott. Yes, I appreciate the question. I think as we think about maintenance program next year, of course, we haven't given formal guidance as to what that looks like yet, but that's certainly what we are leaning towards right now. As we've all seen, the commodity prices are very volatile and the fact that we swung nearly $5 in the past 2 days. And so it's really interesting to think about how we look at next year, what it's going to look like. I think what you've seen from us, both from a hedging profile as well as how we've managed our debt and liquidity this year is that we're keenly focused on all of those metrics combined. And so yes, maintenance program is our plan next year. We're certainly going to be aware of our liquidity and our leverage throughout the year. So depending on how commodity prices look, that will affect, of course, our outspend or if there is one next year at all. Depending on how you look at prices, strip prices today might suggest that there might be an outspend. But again, it's really difficult to forecast what that looks like. If there were a modest outspend next year, which we'll see how that looks, if you think about Q3 and Q4 of this year where we generated positive free cash flow, that positive free cash flow is enough to support a maintenance program next year, even if there were a slight outspend. So it's essentially a debt-neutral situation. So we feel very comfortable that we can attain a maintenance program from exit rate of 2020. Does that make sense?

Yes. Yes, that does. I appreciate it. And I'm sorry, did you say -- did you have an idea of the well count that would keep -- take to keep production flat?

We haven't provided that yet, Scott. I think you can use about 18 wells per rig, and we set approximately 2 rigs next year. So I think that gives you some rounding numbers that without giving some specifics on our 2020 guidance, that gets you pretty close.

No. I appreciate that. And then you talked about -- or there were discussion, I think, by Matt, on, I guess, doing some swaps and trades in getting to around 80,000 net acres. And can you give us a bit of color on what's happening around your position? Is that related to the Noble Chevron deal? And where do you all fit in sort of this consolidation conversation? I mean part of it is getting your cost structure down to make a better business, but there's also the part where it's getting some scale, and sometimes it's for relevance rather than just corporate efficiencies.

Sure. Yes, Scott. That's multiple questions, I think, within that question, but those are all good ones. Our acreage position, as we've said in the call, is going to exit the year greater than 80,000. It will likely be more specific to that next quarter as we get to the end of the year and can truly tally up how we've done. It's a big complement to our land team. They continue to have -- be proactive on trades and swaps with our offset operators, increasing our working interest in existing units, turning non-op sections into operated sections. And oftentimes, those trades are not exactly one for one on acreage. And so we've been able to add cost free acres to our position throughout the year. So that's how you've seen that. You saw that our land spend for the quarter was very modest. And so again we spent very little on land, but we're still able to increase our position. So feel very good about that. The second part of your question was really about consolidation. And I think that the industry has certainly seen a wave of that, particularly with the large and even some mid-cap companies. I think that the size and scale are a good thing, and it will make its way down to the smaller companies. Right now we haven't seen a whole lot of that. And I think it's a matter of time when that occurs from -- well, how do we fall into that kind of corporate consolidation world? I think that anything that looks constructive to our shareholders, accretive to our metrics and then can generate value for the stakeholders to the company, we would certainly consider that. And I think somewhere down the road, getting bigger does make sense for us. What we are focusing on today, though, is all about costs and then delevering the company. I think getting to free cash flow and continuing to organically delever the company is what we're focused on today.

Your next question comes from the line of [ Steven Decartes ].

Just wanted to see with 3Q '20 well cost at $858 per lateral foot, what you see of the drivers to get those costs down to that $750 to $850 range that you're looking for on a go-forward basis?

Yes. I'll let Matt take this. Go on answer his question.

Yes. The numbers that we talked about with regard to the DUCs were around $858 per lateral foot. And yes, what we were mentioning in the script was really that we had the advantage of recent completion activity, recent facilities builds and -- but those costs of $850 -- sorry, $858 were burdened by kind of an older drilling design program that was utilized before we shut down and kind of rebuilt that department. So the expectation of getting closer to the $800 mark, which is kind of within the range of what we've described in the presentation, are really going to be execution of our drilling efficiency plan. And that is -- what I've seen so far is a real focus on the flat time improvements on the drilling rig, little things like trip times and connection speeds and things that are just taking, frankly, minutes where they used to take hours, those kinds of things whittle away at your daily cost, and they improve your efficiency in the field. So it's a lot of just blocking and tackling, changing different wellbore designs, casing programs in Texas and improved drilling efficiencies up in New Mexico. That's how we plan to attack and focus on getting to that $800 a foot range. And really, those are the structural changes that I keep implying when we walk through the script and talk about the importance of the engineers being there in the field in Midland being physically present to just maintain that really high level of oversight on all those flat times. Does that answer your question?

Yes. That's great. And then just as a follow-up, I just want to see if you think there's maybe an opportunity for CDEV to do another debt for equity swap sometime maybe next year.

Yes. This is George, [ Steven ]. I think right now, we're very focused on our cash flow profile and maintaining good liquidity. We wouldn't comment on any type of corporate initiatives, specifically like that. I mean we're very pleased with the outcome of the exchange we executed back in the springtime, which reduced our total debt by $127 million in reduced interest expense. But as I said right now we're very focused on reducing our cost structure, improving liquidity organically and starting to pivot towards 2021 planning and guidance as we move into early next year.

Your next question comes from the line of Don McIntosh.

I just had a question. Maybe if we could revisit some of the improvements you all have made on the LOE front and cost structure in general. With -- you've given an updated full year guidance, but how -- as you kind of exit the year and we think about 2021, a lot of these things do seem like they're pretty sticky. And just as we kind of think about the cost structure next year versus this year, is it safe to assume there's going to be some further improvement on an annual basis?

Yes. Thank you for pointing out, Don. It's -- as Matt described, we're very proud of the team for driving down a lot of those costs, and they -- a lot of them are, as you described, more sticky in nature. The electrification, the swap out of ESPs to gas lift, those kind of things are material improvements that are going to be around going into next year and beyond. So feel good about that. We still have a little bit left on the electrification to finish up in Q4, which ought to help remove some additional generators from the field. And so there are still some projects that we think can help move LOE down on a notional sense. That being said, if you look at our guidance, you'll notice that LOE is up a little bit, I think, from where we ended Q3 for the year. And part of that is just the denominator of that, and that production will be down a little bit in Q4 because our lack of activity in the second and third quarter of this year. So what we've said is that if we hold a maintenance program, it will be from the Q4 level or at least exit rate of 2020 going forward. So if you want to think about kind of a Q4 LOE run rate going forward, that it's not a bad place to use as an estimate until we give 2021 guidance.

Okay. Great. And then I guess just a little more on that. We've talked about it, but you've got a rig back out there now, if we look at the updated guidance, at the midpoint, a couple more spuds, but the completions are maybe up by half a completion. So what would be some of the things that might push you to bring some wells on at the end of the year is kind of the plan for the next 2 months to really just put a couple more DUCs back on the books to kind of help you mitigate that decline and really get going on that maintenance program as we move into '21.

Right. Yes, I appreciate that. So we've got -- as we mentioned, we have a rig in Texas right now drilling. Essentially, it's a 4-well pad, and so the timing of which those wells get to total depth, and then depending on how we fall kind of relative to our capital program and whatnot and the timing of which those wells could be ready to complete, all of that gives a little bit of variance as to exactly how many wells will be completed this year. We think about completed wells as first flowback. So there's a lot of moving parts that could come towards the end of December and whether or not those roll into 2021 or if they're 2020 completions. That's why there's a little bit of a variance on that range. So that being said, we're pleased so far with the way these wells are drilling and look forward to bringing them online either end of this year or first part of next.

[Operator Instructions] Your next question comes from the line of [ Jordan Navis ].

A bit on decline rates. You touched on it earlier, but I just wanted to get a sense, do you kind of have an idea of what the incremental impact on reducing decline rates has on overall breakevens? And then kind of along with that, just what sort of a steady state 2021 maintenance program might do to that 30% to 35% decline rate that you guys were talking about moving into year-end?

Sure. Thanks, Jordan, for the question. We haven't provided a breakeven number out there. It's just something we haven't put forward. I would just encourage you to look at our costs and kind of come to your own conclusions there. But it's -- I feel very good about our capital efficiency as well as our operating costs. And I think we are pushing those in the right direction, which help lower breakeven costs, of course. From the corporate decline rate question, we're going to exit the year, as we mentioned, between kind of 30% to 35% range. I think if you hold that number relatively steady throughout 2021, you're going to be in the right ballpark. And that is due to the fact that we are planning on adding a little bit of activity. Of course, we added a rig in September of this year. What we said on the call is that we're likely to have 2 rigs running next year. And so with that level of activity, I would expect our corporate decline rate to be about flat through 2021.

And just to follow-up on that. Just on the infrastructure spend, that's clearly come down pretty significantly, not only this year, but compared to last year as well. Do you think -- are we at a state now where we're kind of in a steady state spend on infrastructure? Are there other kind of LOE enhancing projects that we could look for that might cause that to go up moving into the year-end and into 2021?

Yes. Jordan, it's George. The majority of our infrastructure spend in terms of major projects has been completed. A lot of that occurred in 2019. At the front end of this year, we had some spending, particularly in Q1. But as we look at major projects, we do see a significant decline in infrastructure spending, not only from the beginning of this year but year-over-year from 2020 into 2021. As we think about, obviously, we guide facilities and infrastructure capital together, so it's one bucket. And as we look towards next year, on the facility side, because we're going to be completing wells on a more normalized basis in terms of our resumption of activity, we will see some degree of increase in the facility spend. But on infrastructure, we're feeling very good about where we are in terms of not having much spend going forward.

Jordan, you might have cut out there. I'm not sure. Did that complete your questions? I apologize.

I believe so. Rens, do we have any more questions in the queue?

[Operator Instructions] You have your next question from [ Nathan Rain ].

You've got Sean Smith here.

I just wanted to get clarification because I know there's a little bit of confusion as far as compliance goes. My understanding that we have an additional 180 days that we can apply for, is that correct?

Are you talking from a delisting point of view?

Yes, sir. Yes.

Yes. We have -- we received a delisting notice in August. We have until February for compliance in the first phase. There is a second phase that would extend that to August. So there's, frankly, a lot of time to deal with the NASDAQ listing requirements. And there are avenues to address that. I'm sure you've seen many companies address that through stock splits and what have you. But we're still early days relative to that and don't anticipate any issues there.

There are no further questions at this time. Presenters, please continue. Thank you all for participating. This concludes today's web conference. You may now disconnect. Have a great day. .