Good morning, welcome to Centennial Resource Development's conference call to discuss its first quarter 2021 earnings. Today's call is being recorded. At this time, I will turn the call over to Hays Mabry, Centennial Director of Investor Relations, for some opening remarks. Please go ahead, sir. Thank you, Thea. Thank you all for joining us on the company's first 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, May 4th, we filed a Form 8-K with an earnings release reporting first quarter 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 forward-looking statement sections of our filings with the Securities and Exchange Commission, including our quarterly report on Form 10-Q for the quarter ending March 31st, 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 presentation or earnings release, which are both available on our website. With that, I will turn the call over to Sean Smith, our CEO. Thank you, Hays. Good morning and welcome to Centennial's first quarter earnings call. This was another quarter of solid results, and I'm extremely proud of our team's performance in the field, particularly in light of the challenging operating environment associated with Winter Storm Uri. On today's call, George will first discuss our quarterly financial results, recent convertible note offering, and capital structure. Matt will then provide an operational update, including recent initiatives and cost reductions, and then I'll follow with capital efficiency and cost gains to date and provide a high-level overview for the remainder of 2021. With that said, I'll turn it over to George to review our financial results. Thank you, Sean. I'll first review our Q1 financial results and then discuss the March convertible notes offering and the benefits associated with the transaction. Turning to our financials on slide 13 of the earnings presentation, net oil production for the first quarter averaged approximately 28,240 bpd which represents an approximate 6% decrease from Q4. Average net equivalent production totaled approximately 54,200 bpd, which was a 9% reduction from the fourth quarter. Q1 volumes were impacted by a lack of completion activity during the prior quarter, as well as production downtime resulting from Winter Storm Uri. We expect that Q1 levels will be a low point for the year as production rebounds in Q2. While production declined quarter to quarter as expected, revenues increased significantly as a result of higher oil, natural gas, and NGL prices. Revenues totaled $192.4 million, which was 30% higher than Q4. Realized oil prices of $52.62 per barrel were approximately $12 per barrel higher than Q4 and drove a 19% increase in oil revenues. Realized NGL prices of $29.78 per barrel were nearly 70% higher than the prior quarter. Finally, natural gas revenues essentially doubled despite a 7% production decline, coming in at $35.5 million compared to approximately $18 million during Q4. Q1 gas realizations of $3.79 per Mcf were heavily impacted by higher pricing during the month of February due to colder temperatures associated with the winter storm. Shifting to costs, all unit costs for the quarter were impacted by lower total equivalent production, and we expect to see notable improvements beginning in the second quarter. LOE per barrel increased by 11% from Q4 to $5.30 per barrel, primarily due to production levels and higher electricity costs caused by the winter storm. Even with approximately $2 million of incremental storm-related costs, notional LOE was actually essentially flat quarter to quarter at approximately $26 million. Excluding these one-time costs, LOE was $4.93 per BOE. Cash G&A on a notional basis was down modestly to $10.6 million, resulting in $2.18 per barrel for the quarter. GP&T was $4.23 per barrel compared to $3.27 in Q4, because our percent-of-proceeds processing contracts are mainly tied to gas prices, which increased dramatically, as I described earlier. Lastly, DD&A decreased 4% quarter to quarter to $13.08 per barrel as a result of lower finding costs and upward revisions to PDP and PUD reserves. In Q1, we recorded a GAAP net loss attributable to our common stock of $34.6 million. Adjusted EBITDAX totaled approximately $100 million, up from $79 million in Q4 due to higher commodity prices. Lastly, even with the resumption of drilling and completion activity that drove CapEx significantly higher, we generated $10.6 million in free cash flow during the quarter. Shifting to CapEx, Centennial incurred approximately $73 million of total capital expenditures compared to $30 million in Q4. We ran two rigs and one completion crew, which drove nine wells spud and 11 completions, compared to essentially one rig, seven wells spud, and zero completions during Q4. Of the $73 million incurred, approximately 97% was related to drilling, completions, and facilities. Infrastructure and land capital totaled $2.3 million for the quarter. It's worth mentioning that the vast majority of the company's infrastructure spending to support full field development was incurred during 2018 and 2019. We don't anticipate any significant infrastructure spending going forward. On slide eight, we outline the key terms and corporate finance benefits of the convertible notes offering that was priced on March 16th. Given that we had a one-year window from issuance to redeem the $127 million second lien note at par, we are very pleased to have been able to access the capital markets to do so. After the exercise of the greenshoe, the company raised $170 million of seven-year, 3.25% senior unsecured convertible notes, which generated net proceeds of approximately $164 million. The conversion premium was 30%, resulting in a conversion price of $6.28 per share. Importantly, the notes can be settled in cash, stock, or a combination thereof at the company's discretion. A significant portion of the offering proceeds were utilized to redeem the second lien note in April, and we also repaid approximately $18 million of credit facility borrowings. Additionally, we utilized a portion of the proceeds to purchase a capped call, which synthetically increased the new notes conversion price to $8.45 per share to minimize potential future dilution. Overall, we are very happy with the offering, and I wanted to highlight several key benefits to the company. First, as illustrated on slide 10, we strengthened our maturity profile by redeeming our 2025 note with a 2028 maturity. This results in our first senior unsecured note maturity occurring in early 2026. Second, as shown on slide eight, we reduced cash interest costs by approximately $4.7 million per year because the second lien note carried an 8% coupon compared to the 3.25% coupon on the new convert. Third, by redeeming the second lien note, we removed some secured debt from our capital structure, which is a positive for our bank lenders. Finally, we significantly increased liquidity because the second lien redemption eliminated the $31.8 million availability blocker that had restricted access to our full borrowing base and a portion of the offering proceeds reduced credit facility borrowings. On slide nine, we summarize our capital structure and liquidity position at March 31st. You will notice that we present the 331 balance sheet in two ways. First, we show the actuals as they appear in our 10-Q filing with both the new convertible note as well as the second lien note still outstanding. However, because we redeemed the second lien note after the quarter ended, we also show a pro forma column that is reflective of that April redemption. Beginning with liquidity, subsequent to the end of the quarter, our $700 million borrowing base was reaffirmed. As of March 31st and pro forma for the second lien note redemption, we had approximately $291 million of credit facility borrowings, approximately $11 million of cash, and $4.3 million of outstanding letters of credit. This results in total pro forma liquidity of approximately $415 million and represents a $75 million increase from year-end. Turning to credit statistics, you may recall on our last earnings call that I introduced the net debt to last quarter annualized or LQA EBITDAX calculation as an additional measure of Centennial's leverage that we believe is more reflective of the current state of the company's credit profile, given our lower production base, lower cost structure, and recent commodity price environment. At March 31st, Centennial's net debt to LQA EBITDAX metric was 2.7x, compared to 3.5 x at year-end, as illustrated in the red dotted box in the table on the right side of slide nine. As shown in the bar chart on the bottom left of that slide, Centennial's net debt to last 12 months EBITDAX was 4.3 x at March 31st, and we expect to end the year well below 2.5x with our two-rig program and assuming current strip prices. I find it remarkable that. That after over a year of significant economic commodity price and financial market dislocations, we have repositioned Centennial as a free cash flow-generating entity with strong liquidity and a solid organic de-leveraging path. It has taken a lot of focus and hard work in both the field and the corporate office, and I wanted to take the opportunity to thank our employees for their efforts. With that, I'll turn the call over to Matt to review operations. Thank you, George. As everyone is aware, Winter Storm Uri created some challenges in the field for operations across the Permian Basin. While George touched on the impacts of the storm from a financial standpoint, I will touch on some of the notable highlights from the field. All told, we experienced minimal operational delays from the weather. Prior to the storm, our team pre-staged diesel fuel on our drilling sites, emptied tank batteries, and prepared to the best of our ability for the coming storm. Because of this, we were able to maintain drilling operations for most of the weather-related events, incurring only two to three days of delay in our D&C operations. This is a testament to our team's resiliency and work ethic. Moving on now. For the quarter, we operated a two-rig program with one frac fleet. Our engineers have been very focused on material improvement in our drilling completions and facilities costs, and I'm happy to provide some color on that work today. As you can see on slide six, we reduced our spud to rig release times by 11% year-over-year to 17.3 days, while increasing our average lateral length for the same period by 17%. Our new three-string casing program in Reeves County has been working very well and is the backbone for our cost reductions in Texas. Our completions team has continued to drive efficiencies in their program, averaging seven stages a day while still pumping very large, high-density jobs in excess of 2,000 lbs per ft. As a result of these initiatives, our well costs averaged $795 per lateral foot for the quarter, just below the midpoint of our cost guidance range of $750 per lateral foot-$850 per lateral foot, and a material 40% reduction from our 2019 numbers. Additionally, we took the opportunity to upgrade our rig fleet to walking rigs, which we believe will further improve our cycle times. We will remain focused on driving further efficiencies in our program and look forward to continuing to raise the bar. Additionally, our facilities group has continued to focus on new designs that materially reduce our costs for multi-well pads, all while upholding our high-quality standards for air emissions. For a multi-well pad with a central tank battery, our facility cost per well has decreased by roughly 30%. We believe these costs, since they can largely be attributable to the design of the facility, are more structural in nature and are pleased with the overall reductions in cost. Under Sean's leadership, the culture of ESG has taken hold across the entire company. In Q1, we released our inaugural corporate sustainability report, and we are very proud of it. Employees at Centennial have taken ownership of the ESG initiatives and have worked collaboratively across multiple disciplines to bring this project across the finish line. As a company, we strive to capture 99% or more of our produced gas volumes. Despite the weather challenges during the quarter, I'm happy to report that we achieved that goal in Q1, and will remain focused on minimizing our flaring going forward. Going one step further, we've taken a hard look at areas that historically have been problematic and have sought additional gas takeaway options, thereby ensuring that we are doing all we can to improve gas capture field-wide. Additionally, both of our drilling rigs are equipped with dual fuel capability. This materially reduces emissions from the rig and positively impacts our cost structure. Also in Q1, we began converting our frac fleet over to dual fuel as well. By the end of May, we expect to have 100% of our frac fleet utilizing dual fuel. We expect to see these reductions from both an emissions and a cost standpoint as the drilling and completions groups fully integrate CNG into our program. In closing, we are excited about our progress to date regarding our costs and efficiencies, and will continue to look for ways to further drive these efficiencies in the program. Now I'll turn it over to Sean for wrap-up and closing remarks. Thank you, Matt. Before we discuss our outlook for the remainder of the year, I feel it's important to recap some of our recent accomplishments, as can be seen on slide five. Last August, I laid out a roadmap with certain goals associated with heightened capital efficiency and free cash flow generation. Specifically, these goals related to driving D&C structural improvements and efficiencies, improving cash margins through LOE optimization and corporate cost control, and proactively managing our balance sheet and liquidity. Over a relatively short amount of time, I'm pleased to say that our team continues to meet or exceed all of the goals laid out last year. Through higher efficiencies and design changes, we have lowered our year-over-year well cost by almost 20%. Additionally, we've stripped out roughly $9 million of quarterly LOE compared to last year, primarily as a result of our electric substation and transition to gas lift. The lowered cost and solid well results have positioned the company to have substantial sustainable free cash flow. Through our recent convertible notes offering, we reduced annual interest expense and increased liquidity while extending our debt maturity profile. In essence, all of these actions and attributes are the hallmarks of Centennial 2.0 and have helped transition Centennial to a sustainable free cash flow-generating company, as evidenced by the past three quarters. As a result of these operational and financial improvements, our game plan for the remainder of the year is quite simple. First, we remain committed to our two-rig program for 2021. Having turned to this level of operations at the beginning of this year, we have now stabilized our production base and will continue the efficient development of our acreage position, which will be underpinned by multi-well pad co-development with extended laterals. We expect this to provide us with a steady base to continue our free cash flow generation, allowing us to further pay down debt and de-lever organically. More specifically, we anticipate a rather material reduction to our leverage, ending the year well below 2.5 x net debt to LTM EBITDA, assuming current strip pricing. Lastly, we will continue to evaluate potential opportunities to gain size and scale and further de-lever, but only if they are accretive to our financial metrics. In closing, on slide 11, we continue to have high-quality assets in the premier U.S. oil basin and an extremely capable technical team. We look forward to continuing to execute on our game plan and building upon our improvements demonstrated over the past few quarters. Thanks for listening, and now we'll go 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 the star and the number one on your telephone keypad. Questions are limited to one question and one follow-up question. If you would like to withdraw your question, press the pound key. And again, ladies and gentlemen, that's star one for any questions over the phone line. We'll pause for just a moment. Your first question will come from Neal Dingmann with Truist Securities. Please go ahead. Morning, all. Thanks for all the details. Maybe my first question is just, you guys continue to bring down your DC&F cost very nicely and I'm just wondering, could you talk a bit about this? I mean, specifically, I'm just wondering what you primarily attribute to some of these improvements. Why I ask that is some others have done this, but it's been done through smaller frack jobs and the like. I'd just like to hear more on your details. Sure. In fact, I'll actually have Matt Garrison tackle that. He's been the champion for pushing down our D&C costs and increasing our efficiency. Maybe, Matt, why don't you talk a little bit about how we're doing that? Sure. Yeah. Neal, we've been really focused on focusing on our flat time, and that's one of the main things. Our guys have been evaluating every element of our drilling profiles. We've actually, in addition to the casing program, with fewer strings of pipe in the hole, we've also been able to change some things with regard to bit size, bit selection. We've gone very far down that hole on the drilling side. On the completion side, it's just a steady, continued effort to reduce our non-productive time and to make sure that we've got good contracts in place for sand pricing and have all the pieces there for continued pressure downward on the cost side. It's a function of the team itself. It's a lot of our people are really just aggressively chasing after all that flat time and all those little opportunities to do things a little bit better and faster than we did before. I hope that helps you. No, great details. Just last, I don't know if you have too much going on, but I'm just wondering, any thoughts on activity up in the Lea County area? Well, as we talked about before, we plan to spend about 70% of our capital this year in Lea, and the remainder in Texas. Part of that is just a function of timing. Our Texas asset is a bit more mature. We had to spend some dollars last year and the previous two years, getting our New Mexico position up and running from an infrastructure perspective. Now that's in place, and we feel like it's the right time to accelerate New Mexico. We're going to emphasize that a bit more this year. Very good. Thanks, guys. Thanks, Neal. The next question will come from Leo Mariani with KeyBanc. Please go ahead. Yeah. Hey, guys. I wanted to just ask quickly here on production cadence for the year. I know there was significant downtime in the first quarter. I was hoping you guys could maybe quantify that. I guess I would expect that production would move up quite a bit in second quarter as that's eliminated. Just looking to the rest of the year, are you expecting some modest growth? Just appears to me high level to get to the midpoint of guide, you have to have a little bit of growth in the second half. Can you maybe speak to all that? Sure. I'll touch on that and see if I can cover that question, Leo, and then, if we need to follow up, we can. Obviously the winter storm certainly impacted production. We did expect Q1 to be down to Q4. That's how we modeled it based on the timing of our rig activity. As we mentioned, we started a second rig up in December of last year, but it takes time to drill a pad and get those wells brought online. Fully expected a decrease in production quarter-over-quarter related to just timing of additional activity. On top of that, we had Winter Storm Uri, which as Matt outlined, we did a great job of minimizing that downtime. A portion of that lower production was due to that. If you think about how much we were down quarter-over-quarter, about half of that or so was due to Winter Storm Uri, and the other half was just normal decline based on our activity levels. Okay, that's helpful for sure. I guess maybe just a high-level question for you guys here. You certainly seem very committed to the two-rig program here in 2021. Just trying to think maybe a little bit longer term, if we continue to see these high commodity prices with oil prices in the mid-60s, as you look maybe to 2022, which could be just a much more balanced market as OPEC is likely to bring a lot of their volumes back on, not have so much spare capacity. Is that a year where you potentially could put a little bit more growth in the business and maybe hedge some of that in order to drive EBITDA higher next year? Sure. Let me touch on this, a second portion of your first question, because it ties into that as well. You mentioned production cadence for the balance of the year. Q1, as George mentioned in his portion, will be our lowest producing quarter for the year. I think we have re-emphasized the midpoint of guidance for the year, which would suggest a pretty material increase into Q2 from Q1. I would say, as we are live and looking at well data, I'm excited about what's coming up in the next quarter and quarters. I think, feel comfortable with our production going forward, if that's helpful. Relative to our activity for next year, obviously, we can't give too many forward-looking comments, but I think we are very focused on generating free cash flow, even in a slightly elevated commodity price environment. By keeping with our current two-rig plan for this year, we think we're going to generate. I think we previously released something in the order of $55 million-$75 million of free cash flow. We think we're going to generate substantially more than $100 million of free cash flow this year based on current commodity prices. Just a two-rig program allows us to generate material free cash flow. The use of proceeds there is to pay down debt and organically de-lever. Feel good about the game plan for this year. I'm not going to give too much look ahead into 2022. We'll see how the world looks then, but feel good about how we're de-levering the company organically. Okay, thank you. Thanks, Leo. Once again, if you would like to ask a question, please press star followed by the number one on your telephone keypad now. Again, that's star one for any questions. We'll pause for just a moment. We do have a response from Chris Dendrinos with RBC Capital Markets. Please go ahead. Hi. Yeah, thank you. You commented that your target for this year for leverage reduction is about 2.5 x. Long term, it's 1.5 x. Is, I guess, that reduction kind of the only use of free cash flow for the foreseeable future? I guess, what target leverage level would you like to get to before you maybe do consider, I guess, increasing activity? Sure. Yeah, appreciate the question, Chris. As commodity prices have held in there and our efficiencies have continued to improve, even since the quarter, I think that our de-leveraging number, as we put in our prepared remarks, is going to be well below 2.5 x by year-end based on current strip prices. Feel good that we're heading in the right direction there organically. The next phase of that, we stated that we'd like to get below 1.5 x as we get towards the end of 2022, and then sub one time as we get into 2023. That's what we're targeting. Use of proceeds is for debt reduction and to lower our leverage right now. We'll be targeting some of those lower leverage metrics before we talk about growth or distributions or anything like that. The use of proceeds right now is really all towards the balance sheet. Great. Thank you. I guess just following up on Neal's question from earlier in regards to D&C costs and efficiencies. You recently upgraded to these walking rigs and mentioned that it's improving some cycle times. Can you comment here, I guess, on where you see well costs maybe progressing or going through the balance of the year? Any, I guess, additional operational benefits that you think the upgrade to the walking rigs might have? Sure. I'll go ahead and take that one there. Those walking rigs, what they really allow us to do is move around on the pad a lot faster. If we have a multi-well pad, two to three to four wells per pad, the increased mobility of that rig allows us to just cut down the amount of time spent between moving from one rig to another. Also, in terms of just transporting it from one pad site to another as I move around, not just on the pad, but the field, it mobilizes and demobilizes generally a lot faster than our historical wells. We estimate somewhere around a day or so of time savings per well on those kinds of in-field mobilizations and demobilizations. If everything is billed on hourly and day rates, those kinds of savings really add up, and that allows you to really trim things down. What it also allows us to do is run simultaneous operations. While we're moving to the next well to continue drilling, we're focusing on reducing that flat time. We can be performing operations, staging the previous well for the next stage of the job. We're allowed to be working simultaneous operations instead of in the past, we had to wait for the rig to get out of the way before we could actually start something. We can really work more SIMOPS at the drilling level in the field. That's where we really anticipate seeing the savings as that plays out, particularly with multi-well pads. It's kind of a compounding effect of continued savings. Great. That's very helpful. Thanks. Okay, I'm showing no questions at this time. I would like to turn the conference over to Sean Smith for any closing comments. I just wanted to thank everyone for listening to today's call. Hopefully, what you heard out of Matt and George and myself was that we are very pleased with our Q1 performance. I think across the board, our numbers are very solid. I think we're all very excited for what's coming ahead in the second quarter and beyond, and look forward to reporting back on that. If there are follow-up questions, I think information has been provided, but please reach out to us and we'll answer any questions that may come up in the future. Appreciate your time, everyone. Ladies and gentlemen, thank you for participating in today's conference call. You may all disconnect at this time.