Good morning, and welcome to Centennial Resource Development's conference call to discuss its 3rd quarter 2021 earnings. Today's call is being recorded. A replay of the call will be accessible until November 11, 2021 by dialing 855-859-2056 and entering the conference ID number 6880769, or by visiting Centennial's website at www.cdevinc.com. At this time, I will turn the call over to Hays Mabry, Centennial's Senior Director of Investor Relations, for some opening remarks. Please go ahead. Thanks, Ren. Thank you all for joining us on the company's 3rd Quarter Earnings 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 3rd, we filed a Form 8-K with an earnings release reporting 3rd quarter earnings results, as well as operational results for the company. 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 in the Forward-Looking Statements sections of our filings with the SEC, including our quarterly report on Form 10-Q for the quarter ended September 30, 2021, 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. With that, I'll turn the call over to Sean Smith, our CEO. Thank you, Hays. Good morning, and welcome to Centennial's 3rd Quarter Earnings Call. Following my introduction, George will discuss our quarterly financial results. Matt will then provide an operational update, including recent efficiency improvements and well results. I'll follow with our updated financial targets and provide a high-level outlook for the remainder of 2021. Overall, I am very pleased with our Q3 results as I believe they demonstrate our continued execution of our key 2021 objectives. During the course of the 3rd quarter, we once again generated record free cash flow, which helped drive significant deleveraging and absolute debt reduction. We also continued to successfully prosecute our development plan in Texas and New Mexico, delivering strong well results with competitive costs while improving drilling and completion efficiencies. Additionally, we recently signed an agreement to monetize a non-core asset in Southern Reeves County that, upon closing, will allow us to further accelerate our debt reduction efforts, improve our overall leverage position, and optimize our future development. With that said, I'll turn it over to George to review our financial results. Thank you, Sean. We delivered another solid quarter with significantly higher free cash flow, substantial debt repayment, and as mentioned, the announced sale of a non-core acreage position. Beginning with the acreage sale, which is detailed on slide 6 of the earnings presentation, we recently signed a purchase and sale agreement for the divestiture of approximately 6,200 net leasehold acres and related assets for $101 million in cash. The assets are located in an area of Southern Reeves County that we did not intend to develop in the near term and is non-core relative to the company's overall acreage, production, and cash flow profile. Third quarter production associated with the assets was approximately 1,600 BOE per day, which represents less than 3% of our total production. The transaction is expected to close in early December, and net proceeds will be used to repay borrowings under our revolving credit facility. Assuming a successful closing and continued debt repayment from projected free cash flow generation, we expect to end the 1st quarter of 2022 with a completely undrawn revolving credit facility. Overall, we're very pleased with the outcome of this divestiture, as we were able to bring value forward from longer-dated inventory and accelerate our debt reduction and deleveraging initiatives. Turning to our financials, which can be referenced on slides 5 and 16 of the earnings presentation. Net oil production for the 3rd quarter increased 5% from Q2 to approximately 33,500 barrels per day. Average net equivalent production increased 6% and totaled approximately 65,100 barrels per day. Total revenues increased by 24% quarter-over-quarter to $288.5 million as a result of higher production levels as well as significantly higher commodity prices. Realized oil prices of approximately $65 per barrel drove a 14% increase in oil revenues. Notably, higher natural gas and NGL prices made a significant impact, with combined gas and NGL revenue up 57% over the prior quarter. Natural gas realizations of approximately $4 per Mcf were up 56% compared to Q2, and realized NGL prices were up nearly $10 to $40 per barrel. Turning to costs, most unit cost metrics were in line with our expectations. Both LOE and cash G&A per BOE increased off of very low Q2 metrics, but were very much in line with the midpoint of guidance, with LOE of $4.79 and cash G&A of $2.08 per barrel. Total G&A increased primarily as a result of stock-based compensation expense that is tied to certain stock grants that have been impacted by the significant increase in our share price over the past 18 months. As you will note from our implied Q4 guidance, we expect stock-based compensation expense to drop significantly in Q4 and going forward. GP&T was $4.03 per barrel, which was up 16% from the prior quarter, mainly because of higher natural gas and NGL prices, which increased the expense associated with our percent of proceeds contracts. Importantly, this increase in GP&T expense was more than offset by the material increase in gas and NGL revenue, which was a net benefit to our EBITDAX and free cash flow for the quarter. DD&A declined to $12.69 per barrel from $13.09 in Q2 due to upward PDP revisions and lower F&D costs, a reflection of the significant strides we have made in overall capital efficiency over the course of 2021. Due to a quarter of solid production growth, continued cost control, and strong commodity price realizations, adjusted EBITDAX totaled approximately $171 million, up 35% from Q2, and free cash flow more than doubled to $77 million, compared to approximately $34 million in the prior quarter. Additionally, we recorded GAAP net income of approximately $37 million. Turning to CapEx, Centennial incurred approximately $79 million of total capital expenditures during the 3rd quarter, which was a 5% decline relative to Q2. We continued to run 2 rigs and one completion crew, which spud 13 wells and completed 10 during the quarter. Of the $79 million in total CapEx, infrastructure and land capital represented $4 million for the quarter. On slides 9 and 10, we summarize our capital structure, leverage, and liquidity, which showed market improvements quarter-over-quarter. During Q3, we utilized free cash flow to repay $50 million of borrowings on the revolving credit facility. Net debt to LTM EBITDAX declined by nearly a full turn, moving from 3x at June 30 to 2.1x at September 30. The pace of our deleveraging has continued to exceed our initial expectations, and as a result, we've revised our leverage target for year-end 2021 down to 1.5x from our prior target of less than 2x. Notably, net debt to last quarter annualized or LQA EBITDAX has already declined to 1.5x at September 30. Additionally, while we haven't yet provided a 2022 leverage target, we believe based on strip pricing, we will be below 1x leverage by year-end 2022. At September 30, total liquidity was nearly $500 million based upon $205 million of credit facility borrowings, $5 million of cash, and $6.5 million of outstanding letters of credit. The $700 million borrowing base was reaffirmed in the fall, but I will note that asset loan value is significantly higher than the borrowing base amount. Given our strong liquidity position, we haven't had a need to push the borrowing base higher, even though our fundamental asset quality and value would support doing so. Turning to hedging, our hedge position is illustrated on slide 11 of the presentation. Our hedging strategy is designed to protect cash flow in the balance sheet against unexpected declines in oil prices, while also minimizing disruptions to operational activity. This is particularly important as we de-lever the balance sheet. We also try to balance the downside protection that hedges provide with upside exposure to commodity prices. For calendar year 2022, we have hedged approximately 11,000 barrels per day on average, using mostly fixed price swaps at around $64.50-$65 per barrel. This compares to approximately 17,000 barrels per day hedged on average for calendar year 2021. Given our deleveraging profile, our 2022 hedges are more heavily weighted towards the 1st and 2nd quarters, where we have approximately 14,500 barrels per day hedged. In the second half of the year, we have an average of approximately 7,500 barrels per day hedged, providing incremental exposure to commodity prices. Lastly, based on year-to-date performance, we are also refining our annual guidance, which includes the anticipated impact of our recently announced divestiture, assuming an estimated December 1 closing date. Annual oil production guidance is being increased by 2% at the midpoint to roughly 31,800 BO per day, and total equivalent production guidance is being increased by 3% at the midpoint to approximately 61,200 BOE per day. As highlighted over the past several quarters, our operations team has continued to drive efficiencies in the field. Therefore, we are increasing the midpoint of our spud guidance by 5 wells to 48 gross operated spuds. As a result of the incremental activity, in addition to higher than expected working interests in wells completed during the year- We've adjusted our full-year capital expenditure guidance to essentially the high end of our previous range. We've also updated our estimates for completions and unit cost metrics, which are all outlined on page 12 of the earnings presentation. With that, I'll turn the call over to Matt to review operations. Thank you, George. Q3 was another solid quarter for the operations group. We continue to realize the significant improvements in cycle times that we highlighted in last quarter's earnings update. Year-to-date cost per foot remains near the midpoint of our 2021 guidance at around $800 per lateral foot, which includes facilities and flow back, as we believe that is the proper way to think about D&C CapEx. In Q3, all of our completed wells consisted of 2 section laterals, and we continued to see the utilization of larger pads and facilities as key drivers of capital efficiency. We continue to look for ways to improve our capital efficiency, both longer laterals and larger pad developments will be two main areas that we will focus on. Additionally, our operations team has been working on well bore design modifications in both the drilling and completions departments. Some of these tests in Q3 resulted in very positive outcomes that we intend to build upon in 2022. Notably, we trialed two different completions designs that yielded a roughly 30% improvement in stages per day. On the drilling front, we have continued to see the benefits of the significant improvements in drill times realized over the course of 2021, and anticipate trialing a new motor and bit design that we've been working on in the back half of this year. We believe this new design has the potential to further reduce our drilling cycle times by an incremental 10%. As you can see, our operations department is constantly pushing the envelope on the technology to drive further efficiencies. The team's continued focus on innovation and efficiency will be particularly critical as we look to help offset some of the inflationary pressures we anticipate in 2022. Now turning to recent wells on slide 8. In New Mexico, the Mozzarella and Gouda wells were drilled as a 4-well development, targeting the Third Bone Spring sand. These approximately 10,000 foot laterals delivered an average IP30 of over 2,100 BOE per day, or approximately 1,600 barrels per day of oil. Further east, in the central portion of our Lea County position, the Crunch Berry wells were drilled in a 3-well development targeting the Third Bone Spring sand with an average of 9,500 foot laterals. Like the Mozzarella and Gouda package, production numbers were robust, posting IP30 numbers of approximately 2,000 BOE per day, or 1,600 barrels a day of oil. Year-to-date, our development packages in New Mexico have all met or exceeded our internal expectations and will continue to serve as a growth engine for Centennial into 2022. Turning to Texas, the Highlander West Deep C-Oh-nine-H is another example of a strong lower Wolfcamp result. Drilled as a single well to finish out a drilling unit, the well result exceeded internal expectations. Drilled to a lateral length of approximately 8100 feet, this well produced an IP30 of approximately 1800 BOE per day or 1400 barrels of oil per day. The Highlander well represents our eighth Wolfcamp C result in Reeves County this year. We've been pleased with the results of that program that have been yielded thus far and expect this target to continue to play a role in our development program in 2022. Overall, our team did a tremendous job during the 3rd quarter and brought online some terrific wells. Underpinned by our structural cost reductions coupled with higher commodity prices, we estimate that all of our wells brought online during the quarter will achieve payout in under 12 months, assuming current strip pricing, and further highlighting the quality of our asset base. To wrap up, in Q3, we continued to build upon the momentum we have witnessed in the first half of the year. We have been very proud of our ability to largely offset year-to-date inflationary pressures with improved drilling efficiencies. We do anticipate inflationary cost pressure in 2022, and that is why we will continue to pursue new technologies and larger scale development to capture additional cost improvements. As we put the final touches on the 2022 drilling schedule in the next month and a half, it is important to note that we anticipate a similar development mix between our two assets as what we saw in 2021, with the vast majority of the development in 2022 being focused up north in the New Mexico asset. The bottom line is that I believe our team is up for the challenge. Our operations and asset development teams have provided a solid foundation for Centennial's well costs and unit metrics. We are all incredibly proud of the work that's been done, and I look forward to updating you on our progress early next year. With that, I'll turn it over to Sean for closing remarks. Thanks, Matt. As evidenced by today's remarks, Centennial had an outstanding 3rd quarter. I'm pleased to have increased our free cash flow and reduced our year-end leverage targets for the second consecutive quarter, in addition to increasing full-year production guidance. Focusing on slide 13, we've transitioned to generating sustainable free cash flow and expect to generate over $200 million in free cash flow this year. Additionally, we've increased our liquidity by nearly 50% during the 1st 3 quarters of the year. While higher commodity prices have certainly helped accelerate our free cash flow and leverage targets, this would not be possible without our materially lower cost structure. In the field, our operations team continues to do an outstanding job driving efficiencies and reducing cycle times, which have materially lowered our go-forward well costs compared to just a couple of years ago. Before I touch on high level strategy, let me first comment on our recent non-core acreage sale. As George mentioned, yesterday, we announced a divestiture in the southernmost portion of our Reeves County position for $101 million. This was a legacy position with quality rock, but given our current portfolio within both New Mexico and Texas, we did not expect to develop this position in the near term. Thus, we view this transaction as prudent portfolio management, considering that our near-term capital will be focused on other areas of our portfolio. Importantly, these sale proceeds will be utilized to repay borrowings under our revolver. As a result of that pending debt repayment, as well as further anticipated repayments funded by future free cash flow, we expect that during Q1 of 2022, we will have repaid our revolving credit facility in full. With line of sight on an unutilized revolving credit facility and continued balance sheet de-leveraging, we expect to have significant flexibility with respect to how we deploy our anticipated future cash flow during the course of 2022 and beyond. Between now and our February earnings call, when we will release our 2022 guidance, we will be evaluating the best use of excess free cash flow, including various shareholder return options. While we are not in a position to provide further details on these topics today, we have already begun in-depth discussions with our board to develop those future plans. Overall, I am very excited to see and recognize how our team has performed this year. Our execution in 2021 sets us up nicely as we head into next year. Furthermore, our increasing free cash flow profile and our continued deleveraging provide us with significant financial and operational flexibility to drive value for the company and our stakeholders. Thanks for listening, and now we'll turn it over to Q&A. Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing star then the number 1 on your telephone keypad. If you would like to withdraw your question, press the pound key. Once again, that's star then the number 1 on your telephone keypad. Your first question comes from the line of Neal Dingmann from Truist Securities. Your line is open. Morning. Sean, you know going forward, certainly gonna have more financial and operational options, you know, given how leverage has come down. You talked about that. I respect you don't have the full details yet on shareholder return, but I guess my question still around shareholder return is a bit more general, and that's, you know, more around some of your peers have gone to and suggested more of a, they think maybe a no-growth plan is best, while others still think, especially your size, that's still best to, you know, to continue to scale up a little bit on a go forward. Again, I'm not certainly asking specifics on how you'd pay out your free cash flow, but I'm just wondering if you would, you know, sort of lean to one of those two, either the no-growth or the scaling direction. Sure. Good morning, Neal. Thanks for the questions. You know, certainly, we're not giving out 2022 guidance. That being said, I think we're being very transparent with the amount of free cash flow that we're gonna generate this year. If you just look forward on a strip basis, that number is going to increase next year. Feel very good about our financial flexibility, as you mentioned, and we described in our prepared remarks, and that we have begun some material shareholder return discussions at both the senior management and the board level. I mentioned in previous calls and conferences that as we approach 1.5x the EBITDA that we would start to have those discussions. That has happened as we plan to end the year at 1.5x, and then have line of sight on being less than 1x levered by year-end 2022. You kinda take all that into consideration, and we've got a lot of options, both from a balance sheet perspective as well as from a free cash flow perspective. I do think that we will continue to have serious shareholder return discussions, both internally and at the board level. In regards to growth, you know, as we think about that into next year, we are currently running 2 rigs. We have been running 2 rigs all year this year. We plan to start next year with 2 rigs. If we were to keep a 2-rig program flat for next year, because of the operational efficiencies that our team, Matt and his team have incurred over the year and expect to incur next year, we think that does provide some growth. While it's a maintenance program from a rig perspective, we do think that there is some production growth that goes with that, to the tune of low double-digit growth, on a year-over-year basis. It's a bit of a combination of all of the above, if you will, Neal. We think we're gonna have substantial free cash flow in a 2-rig program. We're gonna look at a shareholder return program, and all of that is coincident with, you know, low double-digit growth if we were to have a 2-rig program next year. No, I love the optionality. Just to follow up, you know, M&A out there, we've, you know, we've seen larger deals. I'm just wondering how often are you guys, you know, either seeing somebody knock on your door, you know, showing you some things that they have, or I'm just wondering, you know, again, on Wall Street here, we don't see it too much under the hood. I'm just wondering, have things increased as they normally do towards the end of the year or so? Just, you know, again, I'm not asking, you know, what you're gonna do, but just more how active the market is out there, maybe versus, you know, earlier this year. You know, I think it ebbs and flows as all markets do. I think there have been deals that have come across that have been public and, you know, it's hard for me to gauge that. Anytime there's an opportunity in the Delaware Basin, I assure you that our team considers it. What we're not gonna do, and I've said this in the past, is stretch. I think you've seen the numbers. They're very good as a standalone business. We've got, you know, quality long-term inventory. We've got financial flexibility and material free cash flow and a balance sheet that is just in outstanding shape. We're great as a standalone company. I've said in the past, I'll continue to say it. If there's an opportunity out there that adds accretive value to our business, particularly on a cash flow basis, and can compete for capital versus our current inventory, we'll absolutely take a look, and if the price is appropriate, then we'll move forward. But we're gonna be very careful and selective about that because we've got such a positive momentum as to driving value for our stakeholders as is. No, I love the openness. I think investors do. Stock showing that. Thanks, guys. Thanks, Neal. Appreciate it. Your next question comes from the line of Chris Dendrinos from RBC Capital Markets. Your line is open. Hey, guys. I appreciate it. Just kind of following up on your prior comments. It sounded like you said you're gonna start the year next year at 2 rigs. I guess that to me kind of implies that you might be internally considering a 3rd rig. I guess just kind of honing in on that a little bit, you know, what factors are you all kind of considering and weighing in that discussion? Kind of what would tip the scales one way or the other, in terms of activity acceleration, I guess? Sure. Good morning, Chris. Appreciate the question. I'm certainly not implying that there's a 3rd rig that's imminent. My point was that we have 2 rigs now, without providing 2022 guidance, which will come out, you know, in late February. We plan to start the year with 2 rigs, and then we will look at our capital needs, and we will have discussions with the board on what the appropriate level of capital, i.e. rig cadence, will be for 2022. I think that, you know, a safe way to think about it is that even in a model where we have 2 rigs running throughout the year, it provides growth along with free cash flow and allows us to continue to delIver the company. I'll leave it at that. I certainly wasn't implying that, you know, we are near term considering a third rig. As I've said in the past, the world right now, with OPEC+ still holding barrels off the market, with COVID still out there, you know, impairing on the demand side of the equation, we wanna be very careful, and I think the industry should be very careful before it starts talking about material growth, and we are certainly in that same camp. Yeah. Okay. Understood. I guess as my follow-up, you know, you mentioned, you guys are still on track to hit your well cost targets for the year, and you highlighted a number of initiatives that could bias well cost lower in the future. I guess, can you talk about, you know, I guess, current pad development size and lateral lengths? And then, you know, obviously, you haven't, you know, provided any guidance on 2022 yet, but, you know, I guess maybe just thinking about the opportunity to increase pad sizes, you know, what does that kind of look like and what options are available to you all maybe next year and going forward? Sure. Chris, this is Matt. I'll go ahead and take that question there. With regard to current pad sizes and lateral lengths, I think we've been very pleased year-over-year if you kind of look at historically back, where we're, you know, 2019, 2020 kind of timeframe. We were typically, like a 1- to 2-well per pad kind of company, especially predating 2019. Our lateral lengths in general were at around, you know, 7,000 ft or less in prior years. What I've been very proud of our land team and asset team for doing is taking a lot of opportunities in 2020 and this year in 2021 to block up through trades and swaps to get these longer laterals. You know, I think at the beginning of the year, we guided that our average lateral length this year would be kind of in the 8,700 f t range, you know, in terms of an overall average for the program. We've been very happy with the last couple of quarters, you know, both Q2 and Q3 have been in excess of 9,400 ft on average. We've been able to block up and get those lateral lengths up. The pad sizes also, as part of, I think, some of the things we highlighted in the 2nd quarter, we've gone to more of a modular facility that allows us to bolt on and continue to build, you know, units through a common facility. What that's really allowed us to do is push those average pad sizes up from, you know, 1- and 2-well pads to more like 3- and 4-well pads on average for kind of where we're at this year. That's certainly what we hope to kind of be at in 2022, is more of a 3-well to 4-well kind of average for the year. Beyond that, you know, I think given where we're at with our activity levels and things, we're gonna be, you know, a little bit measured with our approach to going much more beyond a 4-well kind of grouping at one time. That's just a function of assessing the current market conditions and where we're at with regard to our activity level at this point. I think, you know, what you should see probably for us is a continued emphasis on these long laterals in excess of 8,500-8,700 ft on average for a program. Wherever we can, we're gonna be pushing these laterals to, you know, around 2 mi. Then you should expect us to place a high degree of emphasis on pads in excess of 3 wells per pad. I think that's kind of our internal goals. Got it. Appreciate it. Thanks, guys. Thanks, Chris. There are no further questions at this time. I would now like to turn the conference back to our CEO, Sean Smith. Great, thank you, Ren. Well, obviously, you know, hopefully what everybody saw from the presentation and from the remarks that the 3rd quarter was a very positive outcome for Centennial. You know, highlighted by, as we mentioned on the call, record free cash flow, continued deleveraging of the business, non-core asset divestiture, which again, will go right to the revolver. As I mentioned, we plan to have our RBL fully repaid in the 1st quarter, which is just an outstanding outcome, and that's really driven by lowering of our costs as well as generating free cash flow. And of course, higher commodity prices are helpful as well. You know, updating our guidance pretty much across the board is another positive aspect of how we are running the business and continue to focus on our costs. All of those things set us up very well for 2022 and beyond, honestly, to allow us to continue to drive value for our stakeholders. I appreciate everybody's time and attention and for their interest in Centennial. Thank you very much. Ladies and gentlemen, this concludes today's conference. Thank you for your participation, and have a wonderful day. You may all disconnect.