Good day, ladies and gentlemen, and welcome to the Laredo Petroleum Incorporated First Quarter 2022 earnings conference call. My name is Amanda, and I will be your operator for today. At this time, all participants are in a listen-only mode. We will be conducting a question and answer session after the financial and operations report. As a reminder, this conference is being recorded for replay purposes. It is now my pleasure to introduce Mr. Ron Hagood, Vice President, Investor Relations. You may proceed, sir. Thank you and good morning. Joining me today are Jason Pigott, President and Chief Executive Officer, Katie Hill, Senior Vice President and Chief Operating Officer, and Bryan Lemmerman, Executive Vice President and Chief Financial Officer, as well as additional members of our management team. During today's call, we'll be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecasts, and assumptions, are intended to be covered by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Our actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we'll be making reference to non-GAAP financial measures. Reconciliations to GAAP financial measures are included in the press release and presentation we issued yesterday that detail our financial and operating results for first quarter 2022. The press release and presentation can be accessed on our website at www.laredopetro.com. I'll turn the call over to Jason Pigott, President and Chief Executive Officer. Thank you, Ron. Good morning, and thank you for joining us today for a discussion of our first quarter results. We performed extremely well in the first quarter, continuing the momentum we generated in 2021. First, total oil and total production and capital were in line with guidance as the teams continued to execute our investments in Howard and Western Glasscock counties. Second, we generated free cash flow of $23 million and consolidated EBITDAX of $222 million. Third, we reduced leverage from 2.1x debt-to-EBITDA at the end of the year to 1.9x at the end of the first quarter. We also continued to move forward on our initiative to achieve responsibly sourced gas and oil designation for a portion of our production, which was awarded in April. Vital Energy now has 31,500 BOE per day attributed to a Gold rating, which is required for oil to be considered responsibly sourced. We are the first Permian operator to receive TrustWell certifications. In addition to delivering on our projections in the first quarter, we have positioned ourselves to further deliver on our value creation strategy for the remainder of 2022. We materially increased liquidity as the value of our assets supported a 38% increase in our elected commitments as part of the RBL redetermination. We worked with our service partners to lock in 85% of expected drilling, completions, equipment, and facility spend for the remainder of the year, and we anticipate achieving our leverage target of 1.0x by the first quarter of 2023 at current commodity prices. These successes support the objectives of our near- term strategy to utilize free cash flow to pay down $300 million of debt in 2022, equivalent to approximately $17 per share on our current outstanding share count. This amount of debt repayment would achieve a leverage target of 1.5x by early third quarter and 1.0x by the first quarter of 2023. Our commitment to leverage reduction supports the opportunity to institute a program to return cash to shareholders by early 2023. Oil prices have been exceptionally strong, and the industry is experiencing significant inflationary headwinds. We continue to drive efficiencies to offset the inflationary pressures and secure longer- term pricing where we can. Work of the team has enabled us to maintain our projection of greater than $300 million of free cash flow in 2022, despite increasing our capital budget to approximately $550 million and seeing our operating costs increase by approximately $1 per BOE. We remain intensely focused on executing on our strategy to accelerate value creation for our shareholders and delivering our objectives in 2022. We'll now have Katie Hill provide an operations update. Thank you, Jason. As you can see from our first quarter results, our operating teams performed very well again this quarter. Our production, capital expenditures, and number of wells completed and turned in line were all in line with guidance. We did see a couple of days of weather disruptions early in the quarter, but the overall impact was relatively small, decreasing quarterly oil production by about 150 barrels of oil per day. We continue to see solid well performance for both our base and new production in Howard and Western Glasscock counties. We are especially encouraged with the production from the two Middle Spraberry appraisal wells completed late last year in the North Howard area. The performance of these two wells strongly supports the assumptions we made when adding Middle Spraberry locations to our Howard County inventory. Based on the strong performance of these two wells and their strong economics, we've included eight Middle Spraberry wells into our 2022 development plan. These wells will be incorporated into our current activity levels of two rigs and one frac crew and are not being added as additional activity. We are simply adding wells to currently planned well packages in North Howard to benefit from the efficiencies inherent in larger packages. There are no changes to our spud or completion counts for the year. During the first quarter, LOE was higher than we anticipated, reflecting both inflation and additional costs associated with integration of our recently acquired properties. A majority of the increase was associated with artificial lift and flowback management on newer wells in Howard and Western Glasscock counties. These included higher generator and fuel costs associated with running our ESPs on new wells in Howard County, using additional flowback crews on older Sabalo batteries with limited automation and higher compression and fuel gas costs for running gas lift on new wells in Western Glasscock. Other cost pressures impacting LOE include higher rates for compression and VRU rentals, workover rigs, diesel and power. We are currently working to manage costs associated with power by switching to LNG generator systems in Howard County and reallocating facilities and artificial lift to Highline Power as soon as it is available in our operating areas. We also expect to see cost benefits from the work we are doing to retrofit older batteries and consolidate production to new Laredo-built facilities in the acquisition areas. With our cost mitigation efforts, we expect to hold total LOE expense relatively flat for the remainder of the year. This is reflected in our second quarter 2022 LOE guidance of $5.35 per BOE, flat to first quarter. Capital expenditures for the first quarter were $171 million, in line with guidance, reflecting the work the supply chain team has done to lock in as much pricing and supply of required goods and services as possible. As we continue to mitigate inflationary pressures impacting the industry, we have locked in second- half pricing for about 85% of our operated capital expenditures for the remainder of the year, including completion services, tubulars and sand. This will significantly reduce uncertainty in the remainder of our 2022 capital expenditures and ensures we have access to equipment and crews necessary to execute on our development program. We have adjusted our 2022 capital budget to $550 million, up about 6%. This updated capital budget fully incorporates the inflation that we have seen to date, contracted second- half pricing, and expected inflation on any areas that are not yet fully locked in for the remainder of the year. Importantly, with the strength of commodity prices and our strong margins, even with the 6% increase in our capital budget, our cash flow forecast for the year remains unchanged. I will now turn the call over to Bryan Lemmerman for a financial update. Thank you, Katie. During the first quarter, we continued to make progress on our overarching financial goal of generating free cash flow, reducing leverage, and ultimately positioning the company to return cash to shareholders in early 2023. As Katie described, inflationary pressures have been impacting the industry and have pushed our operating expenses and capital expenditures above our original expectations for 2022. We are fortunate that commodity price strength and efficiencies at the field level have fully offset these inflationary pressures as our free cash flow outlook for the year remains unchanged at greater than $300 million in the current price environment. Our investments this year, by design, were front-end loaded, so we expect our free cash flow to increase significantly throughout the remainder of the year as quarterly capital investment levels moderate. Our primary focus for the use of our free cash flow remains debt reduction. Previously stated leverage goal of 1.5x net debt- to- EBITDAX should be achieved during the third quarter. At current commodity prices, we expect that ratio to decrease rapidly and to be at 1x by the end of the first quarter of 2023. Our plan is still to utilize our free cash flow to reduce debt by $300 million by year-end 2022. Our recently redetermined RBL demonstrates our bank group's confidence in our ability to deliver on our goals. Besides increasing our borrowing base to $1.25 billion and our elected commitment to $1 billion, they built in additional flexibility for us to determine how we pay down debt. Through the end of this year, as long as our net debt- to- EBITDAX ratio is below 2.5x, we have the flexibility to utilize $250 million of our elected commitment to purchase or call term debt. Structure provides us with maximum flexibility to determine the best course for repaying debt as we generate cash throughout the rest of this year. As we achieve our debt repayment and leverage goals, we expect to be in a position to return capital to shareholders in early 2023. With that, I will now turn the call over to Jason for closing comments. Results in the first quarter are a reflection of our accomplishments over the past three years. The outstanding returns on our wells in Howard and Western Glasscock counties powered our free cash flow generation and deleveraging. The remainder of 2022 will further accelerate this trend as we pursue our goals of $300 million in debt reduction and leverage at or below 1.0x by the first quarter of 2023. We believe paying down debt throughout 2022 delivers substantial value for our shareholders and positions us to begin substantially returning capital to shareholders in early 2023. Operator, please open the line for questions. Thank you. To ask a question, please press star and the number one on your telephone keypad. To withdraw your question, press the pound key. Please stand by while we compile the Q&A roster. Our first question is from Derrick Whitfield from Stifel. Your line is now open. Thanks, and good morning, all. Morning, Derrick. With my first question, I wanted to focus on your 2022 plan and your confidence in executing against it. In consideration of the operating environment and tightness in services, supplies and labor, have there been or do you expect any business impacts beyond inflation? Great question, Derrick. I think we, again, feel really confident with locking in the capital where we did, right now. Again, it was a factor that were an uncertainty for the future. Again, locking in those completion services and some of the other items is gonna be good for us. As far as the other factors, you know, I'm really excited about the wells that we've got coming online in Howard County. We've got our first 15,000-ft wells coming online. We're trying some new stimulation techniques that appear to be doing well. Those wells are just, like, really early in their flow back, so we look forward to talking more about it in probably at the next quarter. Feel really good about where the company is right now, and I think the steps we took on the capital front mitigate a lot of the risks that we would face for the remainder of the year. Our next question is in the line of John Daniel with Daniel Energy Partners. Your line is now open. Hey, thanks for letting the dumb oil service guy ask a couple questions. I appreciate it. I guess this- Yeah. This one would be for Katie Hill. Can you just walk us through what the opportunity set is and impacts to production could be with just a push to greater workover activity? Clearly, you know, as the commodity price has moved around, we keep a really close eye on what we're doing from a workover standpoint on all of our operations. We've talked about it in the past. I mean, we really look at it on an ongoing basis in any environment to make sure that, you know, what we talk about is no well left behind, that we're looking at each individual well and making the right economic decision for that well. You know, as commodity prices have moved around, it really hasn't impacted our workover activity as much as you might expect, just because we have that ongoing, you know, ongoing program in place. Okay. When you look at, like, the new well completion designs today versus maybe four to five years ago, just throwing that out, is there a material uplift at all when you go back then to the sort of the original horizontal wells that were drilled? When do you do that? Yes. In general, we have done very little workover activity in, you know, recent horizontal wells. Meaning recent in the last four or five years. You know, wells that have been drilled in the last four to five years. That's very unusual activity for us. There have been, you know, a few instances, but it's on, you know, something operationally that's very different than the standard well that we've completed. Okay, great. Just one final one from me. As you all look out to 2023, and I know we're still a ways away, at what point do you start reaching out to your contractors just to negotiate pricing or lock that in? Is that too early? Yes. You know, as we were talking about in the last call, locking in second half, you know- Yeah. I really think it's a call on a service-by-service basis. You know, what we've been doing is, in a very rigorous way, the supply chain team has been evaluating both the industry and us specifically, as far as services and what our expectations are with cost trends and then also availability of services. I mean, Jason pointed out that, you know, locking in second half, we believe, really gives us a lot more certainty, really reduces risk on cost, but it also gives us more certainty and reduces risk around service availability. On a case-by-case basis, depending on services, you know, our goal was definitely to get 2022 as locked up as possible to give us certainty around the capital budget that we're executing on. There are services that we've started to talk about 2023, but you know, I think it's just a case- by- case basis as we see those services and expectations change. Okay. Thank you all very, very much. The other thing, yeah, just getting an understanding of oil. There's so much volatility in oil price. You don't wanna be in a situation where you've locked in services at a high price and then, you know, oil drops. I think we'll just, as we get closer to next year, we'll look at that. Fair enough. Thank you very, very much. Our next question is from the line of Jordan Stuart with GoldenTree. Your line is now open. Hey, guys. Thanks for taking the question. Hello. Just first, would love to get an update on the Eastern acreage block. Obviously, with the moving gas prices, would assume these continue to look more and more attractive, but just any more color you guys could provide on that inventory? Yeah. No, I mean, the gas prices are definitely helping out there. When we look at economics, though, the Howard County is so good that they still fall behind that sequentially. Our economic priority is the Howard County, Western Glasscock, and then the core assets. They again do look better with higher gas prices. Western Glasscock is also a little bit gassier than Howard is, so it's supported as well. We really try to drill our best economics first, and right now that's Howard County, and like I said, we're drilling some really good wells out there right now. Awesome. Maybe just in terms of M&A, you know, just curious the opportunity set that's out there, if you guys are kind of continuing to explore additional opportunities. Obviously, the bid-ask is kind of wide according to others, but just curious to get more color on that front, how you're thinking about and, you know, how any deal could potentially be financed. I'll just start with the opportunity set, and then Bryan can speak on, you know, how we might finance it. We continue to wanna grow and achieve scale as a company. We also want to delever at the same time. Anything that we would look at has to, you know, delever us in line with what we're doing today. A lot of the packages that are out there that we've looked at have been a little bit more PDP heavy, so those don't really fit what we're looking at as a company. We wanna continue to build a robust inventory of wells with kinda lower breakevens that can survive a downturn. That's the priority for us, and there just haven't been a lot of those on the market right now. With respect to financing, I'll turn it over to Bryan. Yeah. I think Jason hit on the fact that, you know, we would still need to be deleveraging along the same lines that we are projecting today. As we look at those opportunities, you're right, the bid-ask are quite wide right now. I think, you know, the type of assets that are out there year to date haven't been what we're looking for. Anything that we do would be financed in a way that we would still achieve our debt our leverage reduction goals materially on the same timeline that we've laid out here today. That's how we look at it. As Jason said, you know, debt reduction's primary, and then, you know, you get to return a capital at some point, and the wild card is, you know, when you find an opportunity on the acquisition side to do, it needs to not derail those goals. That's how we're approaching it this year. Awesome. That's helpful. Last one for me. You know, it sounds like you guys have done a great job locking in, you know, your budget for the second half of the year, even though there's this, I guess, 15% variable. Just curious to dig in a little bit more, is there any potential for that 550 number to be biased higher at any point, or we feel pretty good about that number now? Yeah. You know, what we've incorporated in here, again, is service cost, you know, as we've seen inflation, as we've locked those in. What's remaining, you know, the 85% is activity forward for the year. With the activity that's been completed today, you know, we're over 90%, kinda locked in on the service side. What's in the remaining primarily are areas around chemicals and diesel. Very difficult to lock those in, and clearly, there could be some float in those components. Areas that even though we haven't fully locked in, that we believe, you know, directionally where a market may go, we've incorporated that into the budget. We feel really good about this budget. We think it's very tight. It still will be impacted by changes in, for example, diesel being the most impactful if we're seeing significant changes there. Clearly, that could float to the positive or to the negative, depending on what commodity prices are doing. The only other add that I would make to that is the activity levels in this budget are exactly the same as in the original budget. We do not plan on increasing activity. You know, we talked about kind of what the rest of the outlook looks like. It's based on our two rigs, one frac crew. We do focus on maintaining that activity with only having the two rigs and the one crew running. If we see continued performance improvement, you know, activity being pulled into the year, there may be a little bit of that as we continue through the year and really work on getting our performance improvement into the drill and completions program. Awesome. That makes sense. I guess, just in terms of the inflation assumption, obviously harder to lock in the chems and diesel pricing, it sounds like. What is the underlying assumption? Is it 10%, 15%? Just how are you guys thinking about that, just so I could have kind of a ballpark? Yeah. You know, on services, I'll give you one additional example. Out of the two rigs that we're running right now, we will be contracting one of the two rigs. We're working on a contract for second half of the year, and that's in the 15%. But we do feel like we have a very clear line of sight overall on where pricing will be and have that incorporated, we feel, fully into this budget. Any areas like that that we you know have some line of sight on, we have incorporated into the budget. With diesel, for example, you know, it's gonna be where the market goes. Awesome. Thanks for the time, guys. Thank you. Our next question is from Joseph McKay with Wells Fargo. Your line is now open. Hey, guys. Thanks for taking my questions. Sorry, I hopped on a little bit late, so apologize if this was covered, but was just wondering if you could talk about kind of the Howard County well performance and just kind of the impact given where 1Q actual shook out and 2Q guidance, just kind of what your expectations are for the trajectory of volumes for the balance of the year. Yeah, Joseph, this is Kyle Coldiron. In terms of the well performance in Howard County, we are still really encouraged by what we're seeing from our Howard County North acreage. Both the Wolfcamp and Lower Spraberry really are performing well for us up there. We've been especially encouraged by our two Middle Spraberry wells, which we've highlighted in the deck. Those have really surprised us to the upside relative to our expectations. As a result, we've added eight of those wells to our development program in 2022. In Howard County Central, we're still seeing consistent behavior in terms of the wider spacing packages outperforming. We feel like we've got the spacing kinda locked down there in a way that's attractive for us, and we're gonna continue on that path. Got it. Thank you. That's very helpful. My other questions were asked, so I'll turn it back over to you. Thank you, Jason. Our next question is from Nicholas Pope from Seaport Research Partners. Your line is now open. Morning, everyone. Good morning. I was hoping you could talk a little bit on these longer laterals you're, you know, you're focusing on. You know, you mentioned those 15,000-ft lateral is gonna be coming soon. Should we think about those as, like, pure scale-ups in terms of cost and performance? I guess, really, maybe you could talk a little bit about, like, what the drive is to for these longer laterals. Is there a limit that you guys think you could push towards? Or is it purely geometry of acreage? Yeah. Yeah, I'll talk a little bit about cost and performance. We are drawing the first 15,000-ft lateral string component that we've done in some time. As a company, we've actually, you know, drove a number of wells at those lateral lengths. As we transition to more the North Howard area, we're integrating in more 15,000-ft laterals into the program. One of the well packages that we brought on this quarter, well, first quarter, included the first 15,000-ft lateral. From an operations standpoint, everything's gone smooth. We're just finishing up operations, completion operations on the second set, 15,000-ft laterals for the year. There's certainly cost savings on a per- foot basis. You know, that's really the driver for drilling the longer laterals, and we're seeing that work into our overall program on a cost per- foot basis, you know, based on the capital numbers that have been provided. From a production standpoint, I mean, we're assuming that, you know, we'll see comparable performance on a per- foot basis, and getting the first initial results in on the first 15,000-ft laterals. From the standpoint of how, you know, how far can you go, some operators are pushing further than 15. We do not think that's a technical limit. You know, overall, you know, it's really dependent on how the acreage position plays out as much as anything. I'll give an example there. In Central Howard, we went into operations with primarily 10,000-ft laterals because the acreage is laid out perfectly for that. As we move to North Howard, it's a little bit blockier, and it's given us opportunities to extend those lateral lengths. 15, again, is, you know, a good layout for the development from that standpoint. Got it. I appreciate it. That's very helpful. Additionally, could you talk about, you know, I think in the fourth quarter, you guys, you know, had a handful of wells in Glasscock County. Obviously, it's not a, you know, it's not the focus this year, the drilling program. As you kinda get more data, you know, on the Wolfcamp D and some of these newer formations that you're targeting, where do you think that sits kind of in the hierarchy of wells of kind of the total company? Like, how has performance kinda been? I mean, I do know you have the slides here, but where do you think kinda these Wolfcamp D maybe specifically slots into the hierarchy? Yeah. I think it's kinda like I said, we've got it in the slide deck kinda where we're drilling. We're going to the Northern Howard area. It's again got the best economics in the company. A lot of that again is Spraberry performance is much stronger in the north, so the whole package just has great economics all around. As we mentioned, we're even throwing in some of these Middle Spraberry wells because they perform so well. We'll drill up Howard County, and then we go to Western Glasscock, and we will co-develop it with the Wolfcamp D and all the other formations down there. That's kind of our plan is to fully drill up North Howard. Sometimes we've got some lease obligations, and we may need to go down and put a few wells down here and there, but it causes us to move around, but the priority is drill Northern Howard, then go to Western Glasscock. Got it. That makes sense. That's all I really had. The performance- Yeah. I would say the performance is good. We have it updated in our slide deck. Those wells are performing as expected. Excited about the Wolfcamp D. It's just, the economics in Northern Howard are so good that it's hard to do anything else but those. Got it. All right. I appreciate the time. Thanks, everyone. All right. Thank you. Thank you. We have a follow-up from the line of Derrick Whitfield from Stifel. Your line is now open. Thanks, and apologies for being disconnected earlier. Have you guys touched on Project Canary in Q&A? Not yet. We've got David Ferris, our Chief Sustainability Officer, here to talk a little bit about it, though. Fantastic. Yeah, Derrick, go ahead. Yeah, I was just gonna ask if, certainly while not asking you to take a position on whether a methane fee will pass in legislation, could you speak to the benefits of the certification and if you think it will improve downstream offtake options and potentially realizations based on your industry discussions? Sure. Good question. You know, I think the approach that we're taking is this is the right thing to do to meet our 2025 emissions reductions targets that we've put out there. Understanding the emissions on locations, mitigating those emissions events in line with trying to reduce our overall emissions. That's just the right thing to do, and we're focused on that in particular. We do think that there is, and have seen historically, opportunities in the gas market for small premiums to be paid. You're seeing, you know, certain industries, certain countries be more interested in acquiring certified responsibly sourced gas. We think from a gas perspective, that market is a bit more mature, and there are opportunities there. From the oil side, that market, we're seeing that emerge. We are the first, you know, Permian operator to certify our production, and so believe we're at the, kind of on the leading edge of that right now. We are seeing early indication of interest on, you know, additional opportunities on the oil side for small premiums as well. That's terrific. Thanks for your time, and that's all for me, guys. Thanks, Derrick. Thank you, Derrick. Thank you. I would now like to turn the call back over to Mr. Ron Hagood for closing remarks. Thank you for joining us for our update call today. We appreciate your interest in Laredo. This now concludes our call. Have a great morning. This concludes today's conference call. Thank you for participating. You may now disconnect.