Welcome to Devon Energy's First Quarter 2023 Conference Call. At this time, all participants are in listen only mode. This call is being recorded. I'd now like to turn the call over to Mr. Scott Coody, Vice President of Investor Relations. Sir, you may begin. Good morning. Thank you to everyone for joining us on the call today. Last night, we issued an earnings release and presentation that cover our results for the first quarter and our outlook for the remainder of 2023. Throughout the call today, we will make references to the earnings presentation to support prepared remarks, and these slides can be found on our website. Also joining me on the call today are Rick Muncrief, our President and CEO, Clay Gaspar, our Chief Operating Officer, Jeff Ritenour, our Chief Financial Officer, and a few other members of our senior management team. Comments today will include plans, forecasts, and estimates that are forward-looking statements under U.S. securities law. These comments are subject to assumptions, risks, and uncertainties that could cause actual results to differ materially from our forward-looking statements. Please take note of the cautionary language and risk factors provided in our SEC filings and earnings materials. With that, I'll turn the call over to Rick. Thank you, Scott. It's a pleasure to be here this morning. We appreciate everyone taking time to join us. For today's discussion, I'll be focusing on three key topics that I believe are most important to our shareholders at this point. First, a plan to cover our solid first quarter execution. Second, I will run through the steps we've taken to bolster the return of capital to shareholders. Third, a plan to share insights on how our business is positioned to effectively control cost and gain momentum throughout the rest of the year. To start off, let's turn to our first quarter results on slide six, where we had several key highlights. First, total oil production exceeded our midpoint guidance at 320,000 barrels per day, representing a growth rate of 11% compared to the year ago period. This level of oil production was the highest in our company's 52-year history. Our strong well productivity in the Delaware Basin was once again a key contributor to this result, and our recently acquired assets in the Eagle Ford and Williston Basin also provided us higher volumes in the quarter. Clay will touch on our well productivity in greater detail later in the call, but I do want to highlight that the average well placed online in the quarter is on track to recover more than 1 million barrels of oil equivalent. These strong recoveries are right in line with our historic trends over the past few years, demonstrating the quality, depth, and ability to deliver sustainable results across our resource base. Another notable achievement from the first quarter was our team's effective cost management. This was demonstrated by capital expenditures being in line with expectations and operating costs coming in better than our guidance by a few percent. I'll cover this topic in greater detail later in the call with our outlook, This positive start to the year puts us in a great position to potentially spend fewer dollars in 2023 to achieve our capital objectives for the year. With our first quarter capital activity, we limited reinvestment rates to prudent levels, resulting in over $665 million of free cash flow. This marks the eleventh quarter in a row our business has generated free cash flow with oil prices over this time ranging from as low as $40 a barrel to as high as $120 a barrel. This is a great example of Devon Energy's ability to generate meaningful amounts of cash flow, free cash flow across a variety of market conditions, further showcasing the durability of our strategic plan to create value through the cycle and deliver returns on capital employed that compete with any sector in the S&P 500. With this free cash flow, we continue to reward shareholders through our cash return framework, which was well-balanced between dividends and stock buybacks in the most recent quarter. As shown on slide seven, the total cash payout from these shareholder-friendly initiatives reached an annualized rate of around a 12% yield in the first quarter, which significantly exceeds the available opportunities in other sectors of the market. Nearly half this payout was derived from our distinctive fixed plus variable dividend framework. This consistent formulaic approach, which began almost three years ago, has allowed Devon to offer one of the highest yields in the entire S&P 500 since its groundbreaking implementation. Turning to slide nine. In addition to our strong dividend payout, we continue to see attractive value in repurchasing our shares, which we believe traded a significant discount to our intrinsic value. To capitalize on this compelling opportunity, we made substantial progress advancing our buyback program by repurchasing $692 million of shares year-to-date. In addition to our corporate buyback activity, multiple members of our management team, myself included, have also demonstrated their conviction in Devon's value proposition by purchasing stock in the open market over the past few months. With our board of directors approving the upsizing of the capacity of our repurchase program by 50% up to $3 billion, the company is well equipped to be active buyers of our stock over the course of the year. Moving to slide 11, looking to the remainder of 2023, there is no change to our discipline operating plan we laid out for you earlier this year. That our Delaware infrastructure is fully operational and actively ramping to place more wells online, we expect our production to grow over the remainder of the year. This momentum places us right on track to average just over 650,000 BOE per day this year, which translates into a healthy production per share growth of approximately 9% on a year-over-year basis. With capital, we've not made any revisions to our outlook of $3.6 billion-$3.8 billion for the year. As a reminder, this capital forecast assumes a low single-digit inflation rate compared to our 2022 exit rate. However, in the first quarter we did experience service price stability for the first time in many quarters, and we began to see signs of increased availability of goods and services due to an overall slowdown in industry activity. If these trends continue, we see potential for downward pressure on service costs later this year and into 2024. With much of our contract book shifting towards shorter duration agreements, we're now well-positioned to work with our service partners for better terms as more frequent contract refreshment occurs over the next several quarters. Lastly, on slide 12, I believe this chart does a good job of summarizing the competitiveness of our outlook in 2023. With the plan we've laid out, we continue to possess one of the most capital-efficient programs in the entire industry that is self-funded at a $40 WTI oil price. With this disciplined plan, Devon is well-positioned to continue to generate significant free cash flow and execute all aspects of our cash return model, making 2023 another successful year for us. With that, I will now turn the call over to Clay to cover our operational highlights. Clay? Thank you, Rick. Good morning, everyone. As Rick touched on earlier, our team did a great job of meeting the first quarter operational targets through solid well productivity, effective cost management, and the steady progression of upcoming development projects that will benefit us over the coming quarters. Remember, we're focused not just on delivering the numbers for this quarter and year, but also de-risking opportunities for the coming years and also investing in R&D that will create value throughout the coming decade. We're making great progress on all three fronts. This positive start to the year put us in great position to continue to build momentum throughout the course of the year and achieve our corporate objectives for 2023. A significant contributor to the success in this quarter was our franchise asset in the Delaware Basin. As you can see on slide 15, roughly 60% of our capital was deployed to this prolific basin, allowing us to run a consistent program of 16 rigs and 4 frac crews in the quarter. With this level of drilling and completion activity, we brought online 42 new wells in the quarter, with the majority of this activity targeting high-impact intervals in the Upper Wolfcamp. This focused development program resulted in another quarter of volume growth year-over-year, with oil representing 51% of the product mix. While we had great productivity across our acreage position, our performance during the quarter was headlined by our Exotic Cat Radar project. This 6-well pad located in Lea County, New Mexico, targeted a highly productive area with 3-mile laterals in the Upper Wolfcamp. Individual wells at Exotic Cat flowed at rates over 7,200 BOE per day. Per well recoveries from this pad are on track to exceed 2 million barrels of oil equivalent. The flow rates from this activity rank among the very best projects Devon has ever brought online in the basin. Lastly on the slide, another key event for us during the quarter was the resumption of operations at our State Line 8 compressor station. This was possible thanks to the team's timely efforts in securing replacement equipment and the personnel to safely repair this critical facility. This repair work did temporarily limit our production in this part of the field during the quarter, we are confident that we resolved this issue and we do not expect any further disruptions of this nature. Furthermore, we also commenced operations at our State Line 10 compressor station, providing us another 90 million cubic feet of throughput and even more flexibility in the region going forward. Turning to slide 16. As I look ahead to the remainder of the year, our Delaware asset is well positioned to build upon the solid results we achieved in the first quarter. Overall, with the 200 wells that we plan to bring online this year in the Delaware, we expect well productivity to be very consistent with the high-quality wells we've brought online over the past few years. For context, as shown on the chart to the right, this level of well productivity would not only position Devon among the top operators in this world-class basin, but would also surpass the performance of other top shale plays in the U.S. by a noteworthy margin. This impressive well performance, coupled with a long runway of high-value inventory, further underscores the competitive advantage and the sustainability of our resource base in the Delaware Basin. Turning to slide 17. Another asset I'd like to spend some time on today is the Eagle Ford, which is our second highest funded asset in 2023. Over the past few years, we've taken the discipline and scientific approach to refine the next phase of development in this prolific field through thoughtful and measured appraisal work. The momentum generated from these learnings is evident in our current capital program, where we are pursuing tighter infill spacing and have active Refrac program with the goal to efficiently sustain a steady production profile and harvest significant free cash flow. This year we plan to spud over 90 wells with the majority of this drilling focused on redeveloping acreage with much tighter spacing than originally conceived when we first entered the play a decade ago. We attributed this infill opportunity to high reservoir pressure, a fractured network that heals quickly, and low but consistent permeability. This unique combination allows us to pursue significantly tighter spacing with redevelopment activity targeting 16-20 wells per unit across multiple landing zones in the Eagle Ford. In addition to the benefit of oil-weighted recoveries that are projected to exceed half a million barrels per well, our ability to leverage this existing infrastructure in the play also bolsters the returns. These unique and favorable reservoir characteristics in the Eagle Ford provides us with many years of highly competitive drilling inventory. The team has also made steady progress on our Refrac program in the Eagle Ford, achieving consistent, successful, and re-stimulating the productivity of older wells. To date, we have roughly 30 Refrac online that have successfully accessed untapped resource, resulting in an immediate uplift to the well productivity that has expanded per well reserves by more than 50%. In 2023, we plan to execute around 10 Refracs, we've identified several hundred high return candidates across the field to pursue in the future. While we have made significant progress on improving recoveries through infill spacing and Refracs, we believe there's still meaningful resource upside in this play. A catalyst to help us accelerate our learnings in this area is our Zgabay pilot in DeWitt County, which is supported by a grant from the U.S. Department of Energy. The objective of this grant is to fund a field study and create an underground laboratory to improve the effectiveness of shale recoveries by testing new monitoring techniques for both initial stimulation and production, as well as collecting critical data to enhance recoveries via Refracking and EOR. While we're still in the early stages of gathering and interpreting the data from this project, we have already incorporated learnings into our day-to-day operations. These learnings will enable us to optimize recovery of resource and not only in the Eagle Ford, but across our broader footprint in the U.S. I expect to have more positive updates on this topic in the future. Finally, on slide 18, I'm also excited to talk about the positive results we're seeing delivered on other key assets across our portfolio. As you can see on the graphic to the right, over the past year, we've done some good work to opportunistically build up operating scale in these areas and increase the production by 9%. The main factors that drove this growth were our Dow JV partnership, which helped us regain operational momentum in the Anadarko Basin, the RimRock acquisition in the Williston, and the quality assessment work we've done in the Niobrara Oil Play in the Powder River Basin that has helped us build for the future. In addition to solid production growth, this diversified group of assets is on pace to generate a meaningful tranche of cash flow that we can deploy to other key strategic priorities, such as the return of capital to shareholders. I appreciate the team's hard work and the effort that goes into delivering near-term free cash flow and also de-risking valuable future inventory. With that, I'll turn the call over to Jeff for a financial review. Jeff? Thanks, Clay. I'll spend my time today covering the key drivers of our first quarter financial results, and I'll also provide some insights into our outlook for the rest of the year. Beginning with production, our total volumes in the first quarter averaged 641,000 BOE per day. This performance exceeded the midpoint of our guidance for the quarter due to better than forecasted well performance across our asset portfolio. Looking ahead, our second quarter completion activity is weighted towards the back half of the period. As a result, we expect volumes to be relatively flat in the second quarter as compared to the first. However, given the cadence of activity, we do expect to build momentum throughout the second quarter, setting up the third quarter to be the highest production quarter for the year. On the capital front, we invested $988 million in the first quarter, which was in line with expectations. Looking ahead to the second quarter, we expect capital spending to remain essentially flat versus the prior period. As a reminder, we do expect to spend more capital in the first half of the year, given the timing of completions in the Delaware Basin. This higher level investment in the first half of 2023 sets up Devon for a stronger production profile in the second half of the year. Moving to expenses, we did a good job controlling costs in the quarter with several of our expense categories coming in better than forecast. Looking ahead, as Rick touched on earlier, we're seeing cost pressures plateauing across our business. With a solid start to the year, we feel very comfortable with our full year guidance ranges for operating cost and corporate expense. Jumping to income tax, after adjusting for non-recurring items, cash taxes were 11% during the first quarter. This better than expected result was driven by a R&D tax credit that was taken in the quarter. Looking ahead, we expect our cash tax rate to step up to around 15% for the remainder of the year. Cutting to the bottom line, Devon's core earnings totaled $952 million or $1.46 per share. This level of earnings translated into operating cash flow of $1.7 billion. After funding our disciplined maintenance capital program, we generated $665 million of free cash flow in the quarter. With this free cash flow, our top priority was to accelerate the return of capital to shareholders. As we communicated in the past, the first call on our excess cash is the funding of our fixed plus variable dividend. Based on our strong first quarter financial performance, we declared a dividend of $0.72 per share. This distribution will be paid at the end of June, and once again includes an $0.11 per share benefit from the divestiture contingency payments received earlier in the quarter. Another highlight for the quarter was the continued execution of our ongoing share repurchase program. We remain confident in the intrinsic value of our equity as evidenced by the repurchase of $692 million of our stock so far in 2023. With the board expanding our share repurchase program to $3 billion, which is equivalent to 9% of our outstanding share count, we have plenty of runway to compound per share growth as we work our way through the year. Moving to the balance sheet, we exited the quarter with $3.9 billion of liquidity, consisting of $887 million of cash on hand and $3 billion of undrawn capacity on our unsecured credit facility. With this strong liquidity, Devon exits the quarter with a low net-to-debt EBITDA ratio of 0.6x, well below our mid-cycle leverage target of 1x or less. Looking ahead, we plan to further improve our balance sheet by retiring additional debt as maturities come due. Our next debt maturity comes due in August of this year, totaling $242 million. We'll have additional opportunities to pare down our debt with maturities coming due in 2024 and 2025 as well. I look ahead, I'm confident that our financial framework provides us the necessary flexibility to effectively manage through the unpredictable fluctuations of commodity prices while optimizing value creation for our shareholders. With a business plan designed to generate substantial amounts of free cash flow, we'll look to grow our fixed dividend over time, pay out as much as 50% of our excess cash flow via available dividend, opportunistically buy back shares, and take additional steps to improve our financial strength. Furthermore, we possess the flexibility within this framework to lean in to any one of these options to maximize results for shareholders. We believe this balanced and transparent approach is differentiated versus peers. With that, I'll now turn the call back to Rick for some closing comments. Thank you, Jeff. Great job. I'd like to close today by reiterating a few key messages. Number one, our team did a superb job of meeting the operational targets we set out for ourselves in the first quarter through solid well productivity and effective cost management. Number two, our disciplined execution resulted in another strong financial performance for the company. This is evidenced by the attractive per share growth we're delivering, substantial cash returns realized by investors, and the high returns seen on invested capital. Number three, with a solid start to the year, we're now on track to achieve all of our capital objectives in 2023. Inflation is showing signs of plateauing and our business is well-positioned to build momentum and generate substantial free cash flow as we progress through the year. Number 4, lastly, we have the resource depth, execution capabilities, financial strength, and disciplined business model to continue to deliver sustainable results through the cycle. We're a premier energy company and are also perfectly positioned to benefit from this multiyear upcycle. With that, I'll now turn the call back over to Scott for Q&A. Thanks, Rick. We'll now open the call to Q&A. Please limit yourself to one question and a follow-up. This allows us to get to more of your questions on the call today. With that, operator, we'll take our first question. Thank you. Our first question comes from Neil Mehta from Goldman Sachs. Neil, please go ahead. Yeah, thank you so much, and appreciate the time. Rick, you alluded in your comments that you might be tracking towards the lower end of the guide as it relates to CapEx and cost. Can you talk about that and is that a function of any early signs of service cost deflation as well? Well, Neal, I think there's. We're watching a lot of things. We have seen a softening in the market. I think as we've laid out in our guidance, you know, it's really no change. We'll see how it plays out through the year. As I alluded to, and then Clay had in his prepared remarks, we are seeing some softening, and we'll just see on how that plays out. I'd assume right now, no change. The follow-up is just around the Q2 guide, obviously strong Q1 results. Q2 oil guide was a little bit below consensus. Is that just timing of completion and activity and just anything you can say around the cadence of volumes over the course of the year? Yeah, that it is, it is strictly timing. I'll have Clay weigh in on some more color, Neal. Yeah, Neal, just think of the, you know, our band as we try and pursue flat production is somewhere in that 320, maybe 330 or excuse me, 220, 320-330. Excuse me. That band in there. I think the second quarter is gonna be on the low end as we expect that third quarter to be on the high end of that range. No, our original guide, that's still very much intact and feel good about it. As you, as you start really dialing in, I mean, the ±1% of our numbers, it's definitely affected by timing. Do you bring that big pad on early in the quarter, later in the quarter? We've got some other things going. We're a little front-end loaded on the, on the capital with that fourth frac crew, so you'll see that kind of peel off. That affects, kind of the very tail end of the year. We'll see a, the biggest quarter of the year in the third quarter. Makes a lot of sense. Thanks, guys. Thanks, Neal. Thank you. Our next question comes from Arun Jayaram from JP Morgan. Arun, please go ahead. Yeah, good morning. Clay, maybe for you. I was wondering if you could provide some thoughts on the integration of the RimRock and Validus, you know, assets. We've seen production maybe down a little bit since on a per mark, former basis versus when you announced the deals. Wondering if you could talk about how those assets are performing relative to your expectations. Sure. Arun, good question. I appreciate it, and I'll pan out just a little bit because we did, you know, RimRock and Validus kinda back to back. I would say from an integration standpoint, they've both gone exceptionally well. We certainly learned some things on RimRock. We immediately applied to Validus and always looking to continue to get better. You know, specifically on the Validus side, we're certainly learning things I alluded to in some of my remarks, additional upside that we didn't even contemplate in that acquisition. On the RimRock side, you know, boy, the Williston, really the Northern U.S., has been plagued by some pretty cold weather that has not. We've definitely been affected by that. Digging out from that, you know, everyone's reaching for those workover rigs, kind of, all reaching for the same equipment. There's a little bit of a backlog associated with that. Honestly, we've seen a little bit of more offset, frac activity that we've shut wells in for. That impacts things. You know, one of the things we're learning about the late innings in Williston is some of these wells that have kinda complicated depletion, metrics to them. might have may have had a cross cut well that has a lower little bit more depletion in part of that lateral. That's causing us some interesting things around how do we clean these wells out? How do we provide the right artificial lift? We've made some really good strides there. Really excited about the latest group of wells that are coming online. I think all three of those factors have caused us to, probably underperform a little bit in the second quarter relative to expectations, first and second quarter. I see that already in the second quarter, things are starting to pick up, and I'm really excited about, that asset and it continuing to be such a critical piece of Devon's portfolio. Great. My follow-up, Clay, sounds like the team is working on some R&D efforts to unlock inventory. I was wondering if you could maybe detail what exactly you're testing and perhaps some, you know, opportunities to grow your inventory base. Yeah, there's a lot of it going around the company and, you know, a lot of stuff that It's pretty early innings. We're not talking a whole lot just yet. One that we are talking about is in South Texas, the Zgabay project in particular, Department of Energy funded, something that we've shared pretty broadly with the industry in a number of forums. The real wins so far have been from completion design, Refracking, and then the earliest knowledge we're getting around some EOR, some enhanced oil recovery. That's all very exciting. I can tell you we've already put some of that information to work. The Refracking activity is very encouraging. Some of that is pretty unique to the Eagle Ford. Talked about some of the reservoir characteristics there. It has an ability to stay really. The original completion tends to stay very near well bore, and so it gives you that opportunity to feather in a few more wells or other basins that just really doesn't work very well. Then the re-stim, you know, figuring out the techniques, how to go about this, how to prosecute this, and we've seen tremendous upside. All of that is great inventory, and most of it, to be honest, is upside from what we underwrote with the Validus acquisition. Thank you. Thank you. Our next question comes from Neal Dingmann from Truist. Neil, please go ahead. Morning, guys. Thanks for the time. My first question is just on shareholder returns, specifically, Rick, for you are one of the guys. Just are there certain levels where you'd continue to materially lean into the buybacks based on your assumed, sort of mid-cycle prices? Then, you know, if you continue to have some nice divestitures like you had, would those continue to go to incremental variable dips? Yeah, Neal, this is Jeff. Yeah, thanks for the question. What you're gonna see from us is more the same on the model. You described it well, which was certainly to the extent where we see opportunities to buy back our shares when we see that valuation dislocate, if you will, from our view of the intrinsic value, which certainly happened in the first quarter. You know, post our February call, we saw the stock trade on a relative basis to the peers in a negative way, and we jumped in with both feet and bought back shares in a big way. We think that's the beauty and the balance of our... the flexibility of our model, which is it provides us the, you know, the cash and the wherewithal to go take advantage of those opportunities. Moving forward, that's absolutely our expectation. If we see the stock trade-off relative to the group, or dislocate from our view of intrinsic value over the longer term, you should expect for us to lean in on the share repurchase program. All the while, you know, our first priority is to sustain and grow the fixed dividend, which we plan to continue to do, and then feather in the variable dividend. You know, the up to 50% of our free cash flow in any given quarter, is gonna go to the variable dividend. That flexibility and balance that we have in the model, we think has served us really well over the last three years, and you should expect that to continue going forward. Yeah, it's great y'all are stepping into that. Secondly, my question probably, Clay, for you or Rick, just on the delivery infrastructure. Rick, it sounded like you were confident y'all have the needed infrastructure now in place to handle the growth for the remainder of the year. I'm just wondering if y'all could talk about maybe what the build-outs look like or, you know, what type of growth that infrastructure now can handle in the coming quarters. Sounds like it's where you want it to be. Yeah, I think so, Neal. I mean, As I mentioned, Clay, and Clay drove home the point, we're really confident in our infrastructure, actually the recovery and from some downtime, and more importantly, we are staying ahead of it. We have a great team that on the build-outs, it's working really well. We have third-party providers that we have great relationships with, and we have a tendency to try to work a year and 2 and 3 years down the road. When you've got the inventory we do, the execution you do, you can sit down with people and plan that out because that's what the Permian's gonna continue to need year after year after year is continued infrastructure growth, and I'd say it's going real well. No, I appreciate that. Thank you, Rick. Thanks, Jeff. Yeah, thanks. Thank you. Our next question comes from John Freeman from Raymond James. John, please go ahead. Good morning. Thanks a lot. Looking at the success of the 3-mile 3-milers you did on the 6 Wolfcamp wells, do you have a sense of how much of your acres, what% maybe of those undeveloped locations would be candidates for those 3-mile developments in the Delaware? John, I'm gonna wing it a little bit. I think it's about 20%, you know, this year that we're gonna be drilling the three-mile laterals. It's always a little bit in flux. You know, we're always trying to trade the opportunities. I can tell you. You know, we feel very confident in the returns of the two-mile laterals. That's kind of our go-to, with most of our acreage is set up. I think it's just really where we see those opportunities to turn a one mile into a two, or turn a few ones into a three. Those turn into really phenomenal econo-economics. You know, what I would say is operationally, we're very comfortable drilling three-mile laterals today. I think we've got that recipe down. Operationally, it's not a challenge. It's strictly just a looking at the land and where is it set up for 2s and where is it set up for 3s. Great. Just my follow-up question, I just wanna make sure that in the filings, I'm kind of interpreting this correctly. The contingency payments, the remaining $130 million you got from the Barnett. At the current strip, should I assume you get the remaining $65 million, 1Q 2024, the other $65 million, 1Q 2025 at the current strip? Yeah, John, you're exactly right. As it relates to the contingency payments, you know, it varies obviously by commodity price, both oil and gas. At a $65 oil price, which, you know, above a $65 oil price where we are today, we would expect to receive around $20 million. From a gas price standpoint, it's tiered from $2.75 all the way up to $3.50, and the variability there is anywhere from $20 million - $45 million. Where the current strip sits today, I haven't looked at. You know, you're probably somewhere in the mid $3s, I would guess. That'd be another $25 million or $35 million that you could expect to receive on top of that oil payment. That's great. Thanks a lot, guys. Appreciate it. Thank you, John. Thanks. Thank you. Our next question comes from David Deckelbaum from Cowen. David, please go ahead. Thanks for taking my questions today, guys. Just wanted to follow up on some of the thoughts around the buybacks in the first quarter and using the cash balance opportunistically. Does that in any way, sort of inform your view on how you're looking at further consolidation this year? Obviously, Devon was a pretty active participant last year, but, you know, are the opportunities that you're seeing in the A&D market just, sort of less robust than what you would have seen last year relative to the own value of your own stock? You know, Dave, yeah, good question. I think for us, you know, when we did the two transactions last year, we talked about the metrics that we bought those packages at, and you've heard Clay talk about some of the, especially, particularly down in the Eagle Ford, some of the additional upside that we've seen. We feel very, very good about those. I think the market has pulled back up to expectations are a little higher. Some of the packages in the market today, I think we, you know, we'll probably look at them. Once again, we have a high bar and, you know, I don't know that you'll see us being that active in some of the packages that are out in the market today. We'll see how it all plays out. Once again, a takeaway is a high bar, and if it fits us, makes sense for our strategy, then it's something we may consider. I appreciate that. Clay, if I could just ask a little bit more about Zgabay, just more around the scope of the project. How long the DOE grant will last for in this partnership? You know, In terms of EOR, are you looking at gas reinjection or is it all CO2? Is it mostly refracts? I guess just the total scope and duration and how this might be applied to some of your other active basins? Yeah, excellent question. Love talking about it. You know, this was a project that I think was originally conceived in West Texas. That project ended up falling through some great work of our team here, being very heads up, said, "Hey, we've got an opportunity where we can do some of those same things in the Eagle Ford. We've got the right set up, the geology, operations, and it was taken up. We did a lot of very interesting work. We took a horizontal core to really understand that fracture network. You know, I talked about these fractures healing up and what that means to that stimulated rock volume and ultimately our depletion zone that we're seeing on any individual wellbore. We were able to see where do those fractures kind of break through? Where do we actually have proppant, therefore, where do we think we're actually seeing some of the depletion? We've used that information in our stimulation design, knowing what the original recipe was, kinda how do we alter that. As we go back into these Refracs, as you can imagine, it's a mechanical complicated activity. You have to go in and run a liner, and then ultimately you're trying to stimulate new rock. With this information, we've been able to leverage that science and go in and really, we believe, stimulate new and incremental rock and really up the reserves, the recoveries from those original wellbores. That's all been, you know, not just scientifically exciting, you know, in practice, seeing the returns and seeing that value come through. When we look at EOR, this project is really about injecting natural gas in a huff and puff kinda model. That's still an early project. Understanding how that works, we have a lot of monitoring subsurface from gauges to fiber optics, and really watching for what are we influencing from that injection and how ultimately we're recovering more rock. There's a lot of good information out there. The team's done a phenomenal job at presenting at various technical conferences. If you're interested, there's lots of great intel out there to dig further into. Thanks, Clay. Thanks for the time, guys. Thank you, Dave. Thank you. The next question comes from Matthew Portillo from TPH. Matthew, please go ahead. Good morning, all. Morning, Matt. Just to start out, as we look across the portfolio, it's nice to have a diversified asset. Curious as you guys look at the returns by basin and with the volatility in the commodity strip, how you're thinking about capital allocation to some of the basins like the Anadarko in particular, given low natural gas and NGL prices as well as some downside volatility to crude oil as we progress through the year? Hey, Matt, this is Clay. Great question. You know, in the last 12 months, we've kinda tested every every flavor of commodity price, high oil price, low oil price, high relative gas price. We've, you know, 10 to 1, it was $80 and $8 at one point. We've run the sophisticated model that we have in a number of scenarios, really looking for when does our portfolio really command that we shift the capital allocation materially. What was interesting is in all of those scenarios that we ran, even some of the gas levered opportunities, it still said, keep pushing towards oil, keep pushing towards the Permian, the Delaware Basin, was still always commanding capital first. You know, as we've matured our understanding of places like the Eagle Ford, certainly it's risen up. With the acquisition of Validus, you know, it's commanding more capital, as I mentioned earlier. You know, as we stress test the gas side, you know, certainly things like the gas prone areas of the Anadarko become more stressed. Remember, the preponderance of our investment is on the Dow JV, which is the gas condensate area. You get a high, significant amount of condensate in those wells. Also that carry really helps us support pretty phenomenal economics even in this commodity price environment. Now look, we're always watching, we're always rerunning this. This isn't a single once a year scenario. This is a monthly exercise. We're always stress testing, you can bet we're making changes on the margins. You know, we will pull a few wells out of the out of the system for this year, you know, replace a few as opportunities come our way. Maybe it's a trade that just came to us or a new opportunity that the team has discovered. We're always evolving on the margins. What I can tell you is our program is very consistent and very robust, certainly even in today's commodity price and service cost, because we believe the service cost is still decoupled from today's commodity price. Great. Then Clay, maybe as a follow-up for one of the longer data resource basins in your portfolio, just curious your updated thoughts on the Powder? I know it's not overly active this year, but y'all continue to progress the Niobrara in particular. Kinda curious how you've seen results so far and how maybe the costs are stacking up there as well? Matt, great question. I love talking about the Powder because it is kinda behind the scenes. It is something that I'm really, really proud of the work that the team's done. You know, on the front end of the challenge is de-risking the productivity, making sure that when we drill a well, wherever we are in the basin, that we have a good understanding of what it can deliver. The second order is how do we get the cost structure down so that we generate the right competitive return. I can tell you on the former, we've made tremendous progress, and that's really exciting to me. That's the. If you don't have good rock, you can't do anything about that. We've got good rock. We've been able to improve the productivity, prove that uptime and time again. On the well cost, to me, that surface considerations that we can always improve on have a tremendous confidence in the team to be able to drive those costs down in time. That is something we're now working on to ultimately get to a place of more competitive and sustainable returns. You know, we've got a ton of inventory there. It is very oil-prone, and that will certainly have its day in the sun in the coming years. Really great progress from the team there. Thank you. Thank you, sir. Thank you. Our next question comes from Scott Hanold from RBC. Scott, please go ahead. Yeah, thanks. Hey, Jeff, I was just kind of curious. When you step back and look at the balance sheet, I mean, you got about $800 million-$900 million of cash. I know you talked about the, you know, debt coming due you want to take down later this year. You know, as you start thinking about the quantum of incremental buybacks, do you all just really focus on, you know, what is left in free cash flow? Or is there some, you know, optionality to utilize the cash balance? You know, any color on kind of working capital, you know, cash needs for working capital too would be helpful. You bet, Scott. It's a good question, and one we've been thinking a lot about. You know, if you think about our cash balance, what you've heard me say historically is somewhere between $500 million-$1 billion cash balance on the balance sheet is kind of what we try to optimize for and work towards. You've seen us kind of hover around that level certainly over the last several quarters. Moving forward, we're gonna stay focused on the financial model that we've been pursuing for the last three years with the 50%, you know, going to the variable and then 50% accruing back to the balance sheet. We feel really comfortable with our leverage position where it is today. Obviously, we've got a target out there of kind of 1 x net debt to EBITDA. We're significantly below that, you know, currently. We certainly would flex, you know, up and back and forth depending on the market conditions. That again, is what we think is the real, you know, beauty of our model, which it provides us the flexibility as we did this last quarter, to utilize free cash flow generated, whether it's the current quarter or previous quarters, and then push that back into a buyback program, right? Obviously, over this last quarter, we chose to pull down the cash balance. That's certainly something we might do in the future as well, depending on the market conditions that we see. Really it's the, it's the real benefit of the flexibility of the model that we've rolled out, which, you know, allows us to, along with the strength of our balance sheet, to really step in and take advantage of opportunities, whether it be acquisitions that we saw obviously last year, or the stock buyback opportunity that we saw here in the first quarter. Thanks. That's a good answer. You know, maybe this one's for Clay. You know, when you think about the tighter spacing in the Eagle Ford, I know we've, you know, the industry has gone from tightening and widening and tightening and, you know, whether it's a Permian, the Eagle Ford before, and it seems like there's always an aptitude to eventually go back to wider spacing, you know, when oil prices come down. Can you kind of speak to, you know, the resiliency of this tighter spacing if we do see lower oil prices? Do you guys think you'll stick with it, or is that just work, you know, given the current context around oil prices in the strip? It's an excellent point because it, we certainly as an industry, have lived all of those spectrums and myself included. While we generally believe upspacing is the right move in most basins, we would rather have more robust returns and be able to withstand a fall in commodity price. I think that has generally served us better time and time again. As we look at the Eagle Ford, and certainly the maturity of that basin, we're really looking at how do you get those remaining resources most effectively depleted. The work that we did at Zgabay is a significant part of the highlight when you're really kind of sampling that rock, really understanding how that wellbore drainage is really happening downhole. That gives you great insight into not just blindly downspacing and hoping for the best or statistically, hoping for the best. This gives you very good kind of tangible evidence of what we're doing there. We're gonna be real cautious about it. You know, certainly we have, we've been very, very pleased with the results so far. We will continue to watch service costs, continue to watch commodity price, and always reserve the right to get smarter. Fair enough. Thank you. Thank you. Our next question comes from Doug Leggate from Bank of America. Doug, please go ahead. Well, thanks. Good morning, everyone. Thanks for taking my questions. Rick, it's not so long. Good morning. Good morning. It's not so long ago that Devon was not only the best performing stock in the sector over an extended period, but the best performing stock in the S&P 500. I think it was most of 2021, if I recollect. I'm wondering, given that one could argue the market has therefore recognized the value of what the combined company is and benchmarking the free cash flow capacity with, you know, some additional tax headwinds perhaps going ahead, I'm wondering how you would characterize your value proposition today. What do you think you need to do to break out beyond just a call on the commodity? Yeah. You know, I think, Doug, it's incumbent upon this management team. We just need to execute. We just need to stay confident in our plan, our strategy. We got great assets. You know, I do think we've seen some volatility. You speak to the outperformance that we saw a couple of years ago. That's real, very well documented. You know, so when you have a period of softness or what appears to be softness in execution. Whether it's, whether or not, and not whether, but whether or not. We saw a pullback, because it impacted our numbers. I think in my mind, maybe, a little bit too much so. At the end of the day, that sets us up for the share repurchase programs that we just think that our shares are under, way too much pressure. That provides a great opportunity for us and ultimately for shareholders. That's how we're addressing it. You know, bottom line is, we have got, as I mentioned, the assets, we've got the inventory. We're doing some great things. I think you've heard some examples from Clay around some of the technological advancements that we're making. I think in some cases leading the industry. That's gonna continue as part of our genetic makeup. I think we just have to stay after it and stay confident with our plan and keep executing. I think things will work out for us. Okay. I know it's a tricky one to answer, and I appreciate your perspective. My follow-up is on the 0% - 5% growth. Not target necessarily, but outcome that you laid out at the time of the merger. Obviously, the incremental bolt-ons have got you there this year. What about the go forward? I'm thinking, what would the capital budget have to look like to support that? Do you think 12 years of inventory is enough to support that kind of go forward visibility? Yeah. Well, first off, when we talk about the 12 years of inventory, that's make sure you we're honest with each other and we realize that's what's not contemplating the additional inventory that we see out there that will move over into the near term bucket. The way I look at it is we have closer to 20-year inventory when you start looking across our entire asset base, some of the ideas that we have, some of the assessment work that we're doing. I think you and I have talked about that before, of making sure you continue to work for the future. I think we've got an extended runway on inventory. You know, the 0%-5%, that's what we laid out at the time of the merger. We stuck to that gun. The way we've looked at it is really there has not been a huge call on getting up to that 5% growth. Our focus has been let's continue to implement on a per share basis. When you start looking at some of the transactions that we did, the accretion there, you start looking at the buybacks. I think that's what we hear continually from our largest shareholders, Doug, is let's focus on those per share growth metrics, and let's continue to build this thing for the long haul. I like the per share comment. Thanks so much, Rick. Okay. Thank you. Thank you. Our next question comes from Paul Cheng from Scotiabank. Paul, please go ahead. Hi, good morning, everyone. I have to apologize first because I want to go back into the variable dividend and buyback. Rick, you just mentioned that we should focus on the per share matrix. From that standpoint, will the buyback be a more preferred way to return cash to the shareholder than variable dividend? Also then after more than 2 years, have we looked at it, and do you believe the stock or that the company has been rewarded for the variable dividend, given that your yield is so high already? That's the first question. Yeah. Paul, this is- Yeah. Yeah. Go ahead, Rick. Go ahead, Jeff. I'll follow up. Yeah. I was just gonna say, you know, again, Paul, and we talked about this a lot with you in the past. With us, it's all of the above. We've delivered on a sustainable fixed dividend, which we're growing over time. We've got the framework which allows for the variable dividend up to 50% and then stock buybacks on top of that. We're not biased to one or the other. You know, over the long term, we think that balanced approach makes the most sense. Certainly as Rick mentioned earlier, to the extent that we see an opportunity to jump in and buy back our shares when we see a dislocation versus intrinsic value, we're gonna do that, and that has the opportunity to create per share growth for us over time. But at the end of the day, it's about total shareholder return, right? It's not just the dividend, it's not just the buyback, it's not just the stock price, it's that total shareholder return. We think over the longer term, you know, this model and this balanced approach will deliver the best results. I'll point out, you know, over the last 2 years, we're the number 1, you know, company as it relates to total shareholder return, and that includes the last several quarters. We feel pretty confident in our game plan. We're gonna keep our head down and execute and deliver on that game plan. We think when we wake up many, many years from now, we will have delivered a great result for shareholders. Okay. The second question is probably for Clay. I think you mentioned you answered the earlier question saying that 20% of the Delaware Basin well to be drilled this year will be 3 miles. If we look at your risk inventory of 4,500, do you have a rough estimate that what percentage of that number is on the 3 miles? Thank you. Hey, Paul. I'm gonna fuzzy that number on the 20%. Reminder, that's a rough number for this year, and I'm probably a little bit rougher, but I would say directionally it's probably about the same, maybe a little bit lighter to that number. As I think forward on the inventory, remember, a lot of this happens, kind of evolves in our land shop as they make trades and kind of extend that runway a little bit. It's a pretty healthy number. Our standard is 2 miles. Again, the returns on 2-mile laterals in the Delaware Basin are phenomenal. We don't need that 3 mile to make the numbers work. When it comes our way, it sure is a nice thing. Once again, feel very confident in our operational ability to execute on 3-mile laterals. That's become fairly standard fare for the team in the Delaware. Can you just curious that the opportunity of trade up and make the well from, say, 2 mile into 3 miles or even 1 mile to 3 miles, is it, focusing primarily in Delaware or that in other basins that you also, see the opportunity there? Yeah, we, you know, we've drilled 3-mile wells in multiple basins. You know, certainly the Niobrara in the Powder is kinda built on a 3-mile concept. We've drilled at least 20 or 30 wells, 3-mile wells in the Williston. This is something we feel very confident in our ability to execute on. Again, most of our performance, most of our wells we execute on are actually about 2-mile laterals in general. That's become kind of our standard. Where the opportunity presents, we feel very comfortable in executing 3-mile laterals. All right. Very good. Thank you. Thanks, Paul. Thank you. Our next question comes from Roger Read from Wells Fargo. Roger, please go ahead. Yeah, thanks. Good morning. I'd like to come back. Roger ... a couple of maybe the more operational questions. You know, your comments earlier about what you're seeing inflation. Maybe get an idea of how some of the, what's called disinflation maybe at this point would flow through, where you're seeing it, where we should expect to see maybe the bigger benefits. Yeah, Roger, this is Clay. The last couple of, excuse me, the last couple of earnings calls, I've talked more about the tone of the conversation, and I think that's your best, in my view, best leading indicator of where prices are gone. It's gone from a very aggressive, "You will take our prices or you're not gonna get our equipment," circa 2 or 3 quarters ago, to something a little more along the lines of, "Hey, we love you guys. You're our favorite customer. We really wanna work with you, but we're not conceding on price." I would say state-of-the-art today is lots of inbound phone calls, lots of equipment available. They're really trying to hang on to pricing, but some areas are starting to slip, and so we're starting to see some deflation in a couple of categories. You know, the headline, of course, is pipe. We're seeing that kind of materially start to move through in the second half of the year. You know, we're starting to see some smaller categories as well starting to come down. Again, I'll remind you, for us, in particular, we took our fourth quarter numbers, put about a single digit inflation on top of that, and that's kinda how we plan for 23. I think we're still kind of in line with that. We still have contracts, you know, two- and three-year-old contracts that are maturing this year that will be going up to offset some of the wins that we're seeing in the deflationary category. I would say state-of-the-art today, things have leveled out. We're seeing a few wins in a couple of categories. The availability is a material change, and our ability to high-grade equipment, high-grade crews, has really continued to translate into better operations. In fact, moving the wells quicker through the drilling and completion phase. Okay. we should expect not just a decline in cost, but you would expect also an improvement in productivity as you high grade across the board. Yeah. We're definitely seeing some of that. We see some of that in the second quarter, already, you know, activity kinda being pulled forward. These are just kinda few days at a time, but that's, you know, one of the things we're seeing from a capital standpoint in the second quarter. Okay. Great. My follow-up question is on the Refrac wells. I know it's early days in this, I was just curious, you know, is there a type of well or a vintage of well that works best? Going back to a question earlier about, you know, kind of where you should put your money in terms of the returns. I'm guessing oil over gas. Just as a broad comment, how does the return on a Refrac compare to the returns on, you know, new drilling your capital program as currently laid out? Yeah. I think you're in the right categories when you're thinking about what is the ideal candidate. Ideally, really good rock that was really under-stimulated, maybe an ancient design that had a larger final string, like a 5.5-inch casing string that you can run inside of and seal that back off and kind of reperforate and re-stimulate. That's kind of our ideal scenario, but we've tested beyond that. We've said, what about a more modern completion? What about, not the most ideal rock, but kind of the medium rock? We've seen favorable results there. As you can imagine, it stacks up like any portfolio. You have some of your best candidates that compete head-to-head with new wells, and then you have lots of kind of middle-grade contact, middle-grade opportunities, and those are the ones we're continuing to evaluate. Maybe there's a little tweak on the stimulation design that we can push those into the very best category, like some of those ones we've seen up front. Still relatively early days, but very pleased with the progress. Again, this is. The beautiful thing is the land's already paid for, the surface facility is already paid for, the infrastructure's already in place, and that can really help these returns from an immediacy and a capital efficiency standpoint. Appreciate it. Thank you. Thanks, Roger. Well, it looks like we're at the end of our time slot for today. We appreciate everyone's interest in Devon. If you have any further questions, please don't hesitate to reach out to the investor relations team at any time. Have a good day. This concludes today's call. Thank you everyone for joining us today. You may now disconnect your lines.