Good day, ladies and gentlemen. Welcome to Vital Energy Inc.'s fourth quarter and full year 2022 earnings conference call. My name is Mandeep 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, Bryan Lemmerman, Senior Vice President and Chief Financial Officer, Katie Hill, Vice President, Operations, 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 (PSLRA) 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, detailing our financial and operating results for fourth quarter 2022. The press release and presentation can be accessed on our website @ www.vitalenergy.com. I will now turn the call over to Jason Pigott, President and Chief Executive Officer. Thanks, Ron. Good morning, everyone. We appreciate you joining us this morning. Posted strong results in the fourth quarter and full year 2022 and built value on a foundation of recent oil-weighted acquisitions and the efficient development of our quality portfolio. For full year 2022, we had a strong year with the following highlights -- w e generated $220 million of free cash flow and $913 million of consolidated EBITDAX. We purchased $285 million of term debt and $37 million of common stock, reducing our leverage multiple 44% from 2.14x to 1.18x; w e also grew production 19% compared to full year 2021. During the fourth quarter, we generated free cash flow of almost $37 million. We sold non-operated properties for $110 million and we repurchased more than $100 million of face value term debt and almost $11 million of common stock. Operationally, our oil and total production were above the high end of guidance, we showed continued capital discipline with capital expenditures below expectations, w e limited the production impact of severe weather in late 2022 that severely disrupted many Permian Basin operators. Let's talk about 2023 -- this is a challenging time for our industry with oil and gas prices softening over the last few months and service costs remaining high, resulting in lower margins and cash flow. History says the two will find an equilibrium, this will take some time. We are focused today on what we can control. 2023 plan is designed to maximize free cash flow with emphasis on developing our highest return assets and maintaining the strong balance sheet that we have worked so hard to achieve. 2023 plan excluding the recently announced Driftwood acquisition, is largely focused on our most productive acreage in North Howard County where we are seeing strong oil production. Current commodity prices, our 2023 development plan is expected to generate more than $70 million of free cash flow, development drilling continues to bolster our inventory as we have maintained about eight years of oil-weighted inventory, organically adding Wolfcamp D locations in Glasscock County that offset reductions in our Wolfcamp B inventory. For the past three years, we have observed growing industry activity in the Wolfcamp D around our Glasscock County acreage. These results, combined with our own previous drilling results underpin the addition of 80 Wolfcamp D locations in Glasscock County. On slide six of our earnings presentation, we plot industry activity in the Wolfcamp D around our leasehold and show the results from wells we have developed with modern completions. Last week, we announced that we signed a purchase agreement for the acquisition of the assets of Driftwood Energy, t his acquisition gives us a foothold in a prolific part of Upton County, adding about 30 high-margin oil-weighted locations and high oil cut production. Our disciplined approach for creating scale was rewarded with this accretive transaction and we are confident that it will generate material future value for Vital Energy. On slide eight, we show the productivity of the acquired PDP wells and believe the undeveloped locations will be competitive with portions of Howard County. We plan to develop this asset over the next several years without increasing activity levels. Finally, we have high confidence in our 2023 plan, o ur team is executing extremely well today; we plan to maintain capital discipline and a steady pace of development that will allow us to capture synergies and capital efficiencies. Financially, we have prioritized free cash flow, high margins and maintaining a strong balance sheet. Now I'll turn the call over to Bryan for a financial update. Thank you, Jason. I'll start with some comments around our capital budget -- Our 2023 capital investments are expected to be between $625 million and $675 million, new prices have fallen over the last few months and service costs have yet to adjust; we know this takes time but we have factored in approximately 15% inflation over 2022 average levels. Capital expenditures are slightly front-end loaded in 2023 with around 55% of capital expected to be invested in the first half of the year. We're currently utilizing a second completions crew which we plan to release at the end of the first quarter taking us down to one crew for the remainder of the year, we expect to operate two drilling rigs throughout the year as continued efficiency gains in our drilling operations allow them to stay ahead of our completions crew. We announced last week our acquisition of Driftwood. We expect this transaction to close in early April and i t will add PDP production of approximately 3,400 BOE per day, 50% of which is oil, the last nine months of the year; w e will update our combined production guidance at the closing of the transaction. As part of the Driftwood purchase, we also received four DUCs in Upton County that will be worked into our completion schedule this year, w e do not currently anticipate the acquisition will add any capital to our 2023 projections. Finally, we expect a decrease in our RBL net draw from our current net draw of approximately $120 million; t his mid-February amount includes three weeks of payables and no offsetting revenue for February, which will be received later this week, it also includes our semiannual interest payments from January and the Driftwood acquisition deposit. We'd expect quarter-end increases in net borrowings to reflect mainly the interest payments and the deposit. I will now turn the call over to Katie Hill, who joined us last year as Vice President of Operations. Thank you, Bryan. In the fourth quarter, we returned to operating at our high-performance expectations -- both oil and total production exceeded the high end of our guidance ranges despite late December freeze events, our outperformance was driven by improving uptime, upsizing to larger ESPs and increasing deployment of our production optimization technology; with upsized ESPs, we unloaded wells more efficiently, brought new oil production online sooner and more quickly returned Frac- hit wells to previous production performance; o ur winterization preparation delivered weather-resilient operations throughout the fourth quarter. We continued field-wide deployment of production optimization technology to improve bottom hole pressure drawdowns and production uptime and we began to realize the impact of our multi-year digital operations cultural transformation. This performance is also driving production volumes reflected in our guidance for first quarter 2023. Oil production for the year will continue to exhibit some volatility due to the timing and number of new wells. Based on our current development schedule, we anticipate daily production to peak in Q3 for the year; increasing fluid production from our oil-weighted high margin development plan will impact 2023 operating costs. The LOE guidance reflects an increase in total water production year-over-year, increase per barrel water handling cost and additional electrical infrastructure development, this infrastructure will support continued efforts to electrify other operational components of our development plan, including our primary Frac- fleet and in-field compression. Operator, please open the line for questions. The floor is now open for your questions. To ask a question at this time, please press star one on your telephone keypad. If at any point you would like to withdraw from the queue, please press star one. You will be provided the opportunity to ask one question and one further follow-up question. We will take a moment to render our roster. Our first question comes from the line of Derrick Whitfield from Stifel. Please proceed. Thanks. Good morning, all. Congrats on a strong year-end. Thank you, Derrick. Good morning. For my first question, I wanted to focus on the bigger picture for Vital -- now that you've expanded into Upton and you've added organic inventory in the Wolfcamp D; wi th what's been announced to date and the potential you likely have in the Wolfcamp C interval in the Driftwood area, could you comment on your degree of confidence in the eight years you've outlined and share your thoughts on what's the right depth of inventory to attain a fair peer multiple? Great question, I'll answer the first part and then I'll turn it over to Kyle to tell you a little bit more about what we're development plans for the Driftwood area. For us, again, we feel good about the eight years that we've added, again, when I started, we pretty much wiped the slate clean on inventory and have built the inventory we have today -- both organically by testing new formations like the Wolfcamp D or the Wolfcamp B in Howard County, or sorry, the Middle Spraberry in Howard County as well as the acquisitions that we've done and will continue to do; f or us, I think what we're wanna continue to do is build scale, continue to do acquisitions, t he ideal acquisition for us is $400 million-$500 million. It'll bring in 50-100 locations; it's probably $250 million-$300 million in PDP, t hose are the ideal things that we try to do that will, again, if we can continue to do them, one or two per year will eventually grow inventory and we think more, not by extending our inventory to 10 years, but bringing in inventory that will start to feed a third rig and a half completion crew and ultimately two completion crews, which will give us stability w hen we bring in 12 wells a quarter, it can move the production volumes, you know, up and down pretty significantly each quarter. But as we roll the dice more and are drilling 100 wells per year, that allows stability in the production forecast, it allows us to grow; I think those are the things that'll ultimately lead us to the higher multiples and a gain, we've been doing it consistently, w e didn't do as much last year but we had this one kinda in the works for a while and have a strong start for 2023. I'll turn to Kyle just to talk a little bit about the Driftwood. Yeah. On Driftwood, we underwrote that acquisition with our inventory in the Wolfcamp B -- t here are 2 primary Wolfcamp B targets, an upper and a lower and we used a conservative spacing assumption of four wells per target interval, so 8 wells per section; r eally, all the inventory that we're talking about here, the 30 wells is all in the Wolfcamp B but a s you mentioned, there are, you know, this is a stack pay environment, t here are Wolfcamp C wells to our south and to our northwest, we view that as an upside target that we'll be looking at closely to add even you know, future inventory beyond what we've already, you know, stated in our release. Terrific. As my follow-up and perhaps for Katie, in light of your Q4 production performance and stronger than expected 2023 production guidance, could you expand on the impact technology is having on base production optimization and how differentiated your approach is relative to industry? Yeah, another great question, Derrick, I'll take the first part of this and then turn it over to Katie to talk about the operations -- w hen I started with the company, we really wanted to put in place this digital-first mindset, w e've took our existing IT infrastructure and pretty much scrapped it, w e've taken everything to Amazon's cloud and kinda run our data lake and a lot of our operations off of that; what that does is allow us to use machine learning algorithms, AI to optimize our production, f or example, 25,000 or 35,000 barrels per day are on submersible pumps and we're using things like machine learning to change the frequency of the pumps, the pressure we hold on them to both extend life and get more production out of the well. I think those are the things that we are doing that none of our peers are doing it, so we're a leader in that respect, I'll turn it over to Katie and she can tell you a little bit about what they're doing to optimize how we run our routes every day. Thanks, Jason, Good morning, Derek, I think in 2022 -- I would categorize a lot of our operational focus as moving this technology from design into our demonstration phase -- w e achieved really repeatable success in implementing our dynamic routing and some of the base optimization technology that Jason talked about; these tools have helped us over-deliver on our production expectations, as you saw for Q4, primarily by reducing response times for our operators increasing our production uptime and preventing subsurface failures, specifically on ESPs although we're excited to expand that to other artificial lift types; I would anticipate this technology continuing to evolve as we continue to deploy the technology across the assets, particularly focusing on different lift types as we move away from ESPs, depending on where we are in the area. Got it, that's great color, thanks, t hat's all for me. Thank you, Derrick. Our next question comes from the line of Gregg Brody from Bank of America. Please proceed. Good morning, guys. Excuse me. Just a couple questions for you -- first, could you just give us an update on how you're thinking about your long-term debt reduction plan? Has that changed at all as a result of the Driftwood acquisition? This is Bryan, n o, it hasn't changed, I mean, our primary focus is debt reduction and achieving a debt leverage ratio of below 1x and you'll continue to see that be our focus, M&A obviously plays a part in our business, we just have to navigate around that; our focus is getting that debt down below 1.0x, that, you know, as it has been for a couple years, we'll continue on that. I think you also had an implied debt target in there, has that changed at all? Yeah, we had an implied debt target of approximately $700 million last year, y ou know, I think that one will change modestly with acquisitions; y ou know, that one was targeting basically an EBITDA level at a $55-$60 price environment, so as we update our, you know, projections for acquisitions, you'd probably see it, you know, change directionally along those same lines. Got it, j ust the, you have the 25s there, which, curious how you're thinking about them or sort of any refinancing your capital structure in general. Yeah, w e're looking at ways to continue to pay those down, w e, you know, we have the ability to call them under the revolver and pay them down with cash flow; as the year progresses, we'll evaluate everything, a lot of it will depend on the M&A markets and what success we have there but you know, we're keeping an eye on all the markets. Just the last question for you, y ou commented on the increase in costs that you expect this year on the operating side, I see for the guidance number you gave for first quarter, is that a fair number just to assume for the year or will that change at all? I think it's directionally accurate for the year, we are excited to continue to grow in Howard County and as we bring some of those oil-weighted, really high-margin wells online, we're increasing our total fluid production; continuing to build out our water and electrical infrastructure to support Howard County development. Yeah, Katie's referring to LOE -- on the capital side, again, we're gonna be more heavily weighted for the first quarter just because of that extra frack crew that's running in the first quarter and then capital will come down in future quarters as that crew is released. Thanks for all the clarifications. Our final question comes from Nicholas Pope from Seaport Research. Please proceed. Good morning, everyone. [crosstalk] I was hoping you could talk a little bit about, I guess two parts here with the Driftwood asset -- k inda curious how you think the returns kinda fit into the whole hierarchy of what you have in Howard and in Glasscock and also just really the well cost as you look at the new Driftwood assets; are we expecting the same kind of lateral length, same kind of size of wells as you look at and well costs down there in this Upton, this new Upton asset compared to kinda what you have in hand in Howard and in Glasscock? Yeah, that's a great question, on our deck that's published online, we have a, s orry, it's I'm on the wrong slide here; s lide eight, s orry, got a new deck, s lide eight -- we have a production comparison of the wells from Driftwood versus Howard County, Western Glasscock, so the wells at Driftwood are very comparable on a production side to our wells in central Howard County a nd then what we're working through now is just completion optimization and things like that; I'll turn it over to Kyle for a little more color kinda on how we're thinking about that. I would say from a capital cost perspective -- there's a lot of similarity between our Howard County wells and what we're modeling here for Upton and Reagan, you asked a question about lateral length; all of the inventory, the 30 wells that we're talking about are all 10,000 foot laterals, very similar to our, you know, base development plan that we have in Howard County and in Western Glasscock, so I would say a lot of similarity in the capital cost not a material difference between the two. There's, from a geometry standpoint, there's no problem being able to kinda, I think y'all have been averaging 11,000 foot up in Howard; are y'all able to get the 10,000 plus type laterals with the kind of footprint that you have in Upton? In Upton it really is 10,000 foot is kind of the base, the base design and kind of what we're planning on based upon the footprint, t he reason that we're averaging 11,000 up in Howard is 'cause we often have 15,000 foot laterals that are kind of sprinkled into our development plan, typically, we either drill 10s or 15s -- t hose are kind of our two types of designs that we typically drill but in Upton it is all 10,000 foot laterals. Got it, I appreciate it, t hat's all I had, guys. Thank you. [crosstalk] That concludes today's questions. I would now like to turn the call over to Ron Hagood for closing remarks. I'd like to thank you for joining us this morning and we appreciate your interest in Vital Energy. This concludes today's call. Thank you, ladies and gentlemen. This does conclude today's call. Thank you for your participation. You may now disconnect.