Welcome to Devon Energy's first quarter 2025 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 Mrs. Rosy Zuklic, Vice President of Investor Relations. You may begin. Good morning, and thank you for joining us on the call today. Last night, we issued Devon's first quarter earnings release and presentation materials. Throughout the call today, we will make references to these materials to support prepared remarks. The release and slides can be found in the investor section of the Devon website. Joining me on the call today are Clay Gaspar, President and Chief Executive Officer; Jeff Ritenour, Chief Financial Officer; John Raines, SVP Asset Management; Tom Hellman, SVP EMP Operations; and Trey Lowe, SVP Technology and Chief Technology Officer. As a reminder, this conference call will include forward-looking statements as defined under U.S. securities law. These statements involve risks and uncertainties that may cause actual results to differ materially from our forecast. Please refer to the cautionary language and risk factors provided in our SEC filings and earnings materials. With that, I'll turn the call over to Clay. Thank you, Rosy. Good morning, everyone, and thank you for joining us. Devon delivered a very strong first quarter, driven by a focus on operational excellence and financial discipline. Today, we will share how we're accelerating our strategy to drive sustainable shareholder value. Our strategic priorities on slide three are clear: executing on our high-quality portfolio through operational excellence, maintaining financial strength, returning value to our shareholders, and cultivating a culture of success. In a market characterized by dynamic headwinds, Devon stays focused first on what we can control. Leveraging Devon's 50-year history and an experienced leadership team prepared to handle the uncertainty of commodity price cycles, we remain confident in our value creation strategy. We're committed to our capital return framework, underpinned by our high-quality portfolio and our robust financial strength. With an investment-grade balance sheet and a $45 corporate break-even, we are well-positioned to generate value even in a low-price environment. With the recent changes in leadership across our organization and the resulting fresh perspectives, we believe that this is an opportune time for us to accelerate our business optimization efforts and deliver an additional $1 billion in annual free cash flow by year-end 2026. This undertaking demonstrates the creativity, dedication, and talent of our employees, whose continued efforts advance Devon's success. We laid out our targets in our press release last month and look forward to providing additional details on today's call. Our initial expectation was for the material benefits to start to accrue in 2026. We now believe that we can pull forward some progress into this year, and we're cutting 2025 full-year capital by $100 million while maintaining our productive capacity for the remainder of the year. Jeff will provide more details on this optimization plan later in our call. In parallel with our business optimization efforts, we will continue to monitor the broader market dynamics and adjust our plans as needed to maintain our financial strength and deliver top-tier returns for our shareholders. Now, let's turn to slide four and discuss our quarterly results. Our first quarter results reflect consistent, exceptional performance, showcasing the strength of our diversified portfolio. Oil production exceeded the upper limit of our guidance range, reaching an impressive 388,000 barrels per day. This achievement was largely attributed to stronger-than-anticipated base performance in the Rockies and outstanding early well results in the Eagle Ford. From a capital perspective, we also delivered another solid quarter. Effective cost management and reduced infrastructure spending in the Delaware Basin allowed us to keep total capital below our guidance range. Overall, our production performance and capital discipline resulted in a $1 billion of free cash flow generated in Q1. With this significant free cash flow, we returned nearly half to shareholders through dividends and share buybacks. We maintained a sharp focus on disciplined capital allocation, balancing high-return investments with substantial dividends and share repurchases to create sustainable value for our shareholders. Moving to slide five, the Delaware Basin continues to deliver exceptional performance, driven by operational improvements year after year. The expanded implementation of Simulfrac across the asset has been a key contributor, with up to 60% utilization in our 2025 program. This increased adoption has enhanced completion efficiencies by 12% year-to-date and continues to accelerate our days online. On the drilling front, our teams continue to improve efficiency and optimize our rig fleet, achieving a 7% increase in drilling speeds year-to-date. These improvements have yielded meaningful operational changes, enabling us to reduce our rig count once again this quarter. As a reminder, we started the year expecting to run 14 rigs across the Delaware position, but now expect to reduce activity to 11 rigs in the second half of the year. Along with this reduction in rigs in the Delaware, we expect to build in some frac gaps both in Delaware and the Williston, given the improvement to our completion efficiency. Importantly, despite the reduction in rigs and frac activity, we're able to maintain our productive capacity and confidence in our production outlook. This plan highlights our commitment to capturing these improvements through capital discipline rather than growing production in a saturated oil market. Now, let's turn to slide six and talk about the Eagle Ford. As announced last quarter, Devon and BPX Energy agreed to dissolve the partnership in the Blackhawk field. I'm pleased to share that this transaction successfully closed on April 1, 2025. Prior to close, Devon assumed operations of one of the legacy drilling rigs, and our teams have already delivered significant drilling improvements. On our first Devon-operated pad, drilling speeds increased by more than 40% compared to recent legacy performance. These efficiencies, coupled with improved well design and supply chain enhancements, have amounted to nearly 50% reduction in costs. With the cost savings seen to date, Devon is effectively incurring the same drilling capital with double the working interest in the Blackhawk field. Going forward, we expect to realize $2.7 million per well in savings as completions will commence on our first operated pad here in the second quarter. I have confidence that our team will continue to innovate and drive further improvements as we build operational momentum. With these early results, we are delivering on our plan to significantly enhance returns while providing a material uplift to the value of our position. With that, I'll now hand the call over to Jeff. Thanks, Clay. Turning to slide seven, highlighting our first quarter financial performance, Devon's core earnings totaled $779 million, or $1.21 per share. EBITDAX was $2.1 billion, and we generated operating cash flow of $1.9 billion, which exceeded consensus estimates by a healthy margin. After funding our capital requirements, we generated $1 billion in free cash flow for the quarter, reaching the highest level since the third quarter of 2022. Our free cash flow generation was underpinned by oil production that exceeded the top end of our guidance, driven by the excellent operating performance highlighted by Clay, improving gas revenues that increased twofold from the prior quarter, and disciplined capital investment that resulted in an impressive reinvestment rate of 50%. Our strong financial results supported another quarter of substantial cash returns to shareholders. We distributed $464 million through dividends and share repurchases. Notably, we hit the upper end of our target buyback range for the quarter, spending $301 million on share repurchases and bringing the total value of our buyback program to $3.6 billion. Moving to slide eight, we touch on the outlook for the remainder of 2025. Even with the recent downturn in commodity pricing, we're well-positioned to generate attractive free cash flow for the remainder of the year. As highlighted on the slide, at today's strip pricing, we're on track to deliver greater than $2 billion of free cash flow and have a tremendous margin of safety with our break-even funding at around $45 WTI, including our fixed dividend. Furthermore, with our production exceeding expectations in the first quarter, we're increasing our full-year oil production outlook to be in the range of 382,000 barrels-388,000 barrels per day. This higher production equates to a 1% increase to our full-year outlook. In addition, reflecting the responsiveness of the organization to an acceleration of the business optimization plan, we're reducing our full-year capital investment by $100 million to a range of $3.7 billion-$3.9 billion. This reduction is driven by better performance on base and wedge production and the acceleration of capital efficiencies. Turning to slide nine, in the first quarter, our cash balances increased by $388 million, reaching $1.2 billion. This strengthened liquidity position allowed Devon to exit the quarter with a healthy net debt-to-EBITDA ratio of one times. Looking ahead, we intend to use excess free cash flow to further build liquidity and retire upcoming debt maturities. After quarter end, we reached an agreement to sell our interest in the Matterhorn pipeline for approximately $375 million. We expect the transaction to close late in the second quarter, with proceeds further enhancing our cash position and liquidity. Our next debt maturity of $485 million is due in December, and we also have the opportunity to retire our $1 billion term loan in 2026. As Clay mentioned earlier, our broader shareholder return framework remains unchanged. Backed by strong financial positioning, we have the flexibility to advance our debt reduction goals, fund our capital program, and continue delivering significant cash returns to shareholders through our fixed dividend and share repurchase program. Now shifting gears to slide 10 to discuss our recently announced business optimization plan. While we maintain a top-tier portfolio and investment-grade balance sheet, our focus remains on continuous improvement and delivering greater value to our shareholders. This initiative is designed to enhance operating margins, boost capital efficiency, and increase free cash flow generation. Our plan outlines a range of targeted actions to drive more efficient field-level operations, including lowering drilling and completion costs, renegotiating contracts, and reducing corporate costs. Importantly, these efforts extend beyond financial metrics. They reflect the strategic integration of technology across our operations and reinforce our commitment to achieving industry-leading returns. We believe the impact of these initiatives is substantial and unlocks meaningful long-term value for our shareholders. At our current valuation multiples, capitalizing the after-tax impact of the targeted $1 billion of incremental free cash flow could translate to an estimated $10 per share in value, highlighting the significance of this work. Turning to slide 11, we outline the improvements by category and the timeline for achieving them. As you can see on the pie chart, we expect our business to achieve $1 billion pre-tax free cash flow and sustainable annual improvements by year-end 2026 as compared to our previously guided 2025 baseline. Beginning at the top with capital efficiency, we're targeting $300 million of improvements by year-end 2026. These capital enhancements are structural and assume steady service and supply cost. Said another way, we have not assumed the benefit of any deflation from current price levels. Moving clockwise on the chart to production optimization, we expect to achieve $250 million of improvements by reducing downtime, flattening production declines, and optimizing our operating cost structure. For commercial opportunities, our marketing team's contracting strategies are expected to deliver $300 million in total improvements by increasing realizations and lowering GP&T cost. Corporate cost reductions are expected to be $150 million derived from lower interest expense, corporate capital, and G&A. From a timing perspective, we are acting with a sense of urgency. As shown in the bar chart to the right, these combined initiatives are expected to deliver approximately $400 million of cash flow uplift by year-end 2025. Half of this uplift stems from renegotiated contracts already secured by our marketing organization, which will generate over $200 million in improved margins, primarily benefiting the Delaware Basin through lower gathering, processing, transportation, and fractionation costs. These savings will begin to materialize in late 2025 with full-year impact in 2026. To be clear, we have not included any benefit related to the sale of our interest in Matterhorn pipeline in our business transformation uplift potential. Of the $400 million in expected uplift to be captured by year-end, $100 million is attributable to our capital efficiency and production optimization efforts and represents the capital reduction to our 2025 guide disclosed earlier in our comments. Beyond 2025, we anticipate a steady cadence of improvements with all initiatives fully realized by year-end 2026, providing the full run rate billion-dollar pre-tax free cash flow improvement in 2027. With the increased free cash flow, we will remain committed to rewarding shareholders through share repurchases and growth in our fixed dividend, while also strengthening our financial position through continued debt reduction. Slide 12 provides examples of the type of work our teams are pursuing to achieve the targets for each category. I won't talk through the detail now, but in our Q&A session, we're happy to provide some additional color on how we're driving change with our business optimization efforts and creating long-term value for Devon. Bottom line is the teams have proactively begun implementing many of these initiatives. We're confident in our ability to achieve our targets and have a clear line of sight to our objective. With that, I'll now turn the call back over to Rosy for Q&A. Thank you. Excuse me. Thank you, Jeff. We'll now open the call for Q&A. Please limit yourself to one question and one follow-up. With that, Emily, we will take our first call. Thank you. Your first question comes from Neil Mehta with Goldman Sachs. Neil, please go ahead. Yeah, thanks so much. Let's start off with unpacking the cost reductions here on slide 10 and 11 that you talk about, Clay, and to give you an opportunity to kind of talk about your confidence interval around achieving it, when we can really see the run rate, and help us to really itemize some of these buckets. I think people can kind of understand the corporate cost reductions, but some of the other things, like commercial opportunities, are a little harder to put our head around. Just kind of flesh it out a bit. Yeah, thanks, Neil. Appreciate the question. What I would tell you is, so we've done a good job of pointing to things that we can achieve in 2025, again, pulling some of those values, as you saw the capital reduction. As you start working through the list of the other items, I get that it becomes a little bit of two. I'll tell you what, happy to follow up on that, but we've got a few of the experts in the room. I'll start with Jeff, and he can start talking about some of the commercial aspects of it. Yeah, Neil, thanks for the question. Yeah, I'm happy to jump in and talk a little bit about the commercial opportunities. Frankly, that's where we have the absolute highest confidence because we already have those contracts executed. They're in place, and they'll take effect at the end of this year and really into 2026. You'll get the full run rate benefit of that. Just to give you a little bit of color on what we've done there, not a surprise to you, we have multiple midstream partners in Delaware, in addition to the midstream infrastructure that we already own through our Catalyst JV and our Cotton Draw Midstream partnership. That provides us a lot of leverage and opportunity and optionality, frankly, to work with all of our partners and attempt to maximize margins. We had the benefit of a couple of contracts running their course as far as term over the next couple of years, and we took advantage of the leverage that we have with our partners to really go in and look at how we could renegotiate those contracts and drive lower costs. It is a combination of lower fees, higher recoveries. The bulk of that is related to NGLs, our NGL business in Delaware. Bottom line, we have reduced our fees. In some cases, we had legacy contracts that were 2x of what we expect to move forward with going forward. We have managed to reduce our fees on the gathering, processing, transportation, and fractionation. All that will take effect at the beginning of 2026. I feel really confident in our ability to deliver on those outcomes. Hey, Neil, in addition to that, John's here. He can talk a little bit about some of the opportunities in the production optimization. Yeah, Neil, thanks for the question. So far, you've seen $100 million for 2025. Some of that's coming in the form of production optimization. We've seen an incredibly resilient base in the Rockies thus far this year. That's some of the good work that we're already taking credit for. Just to give you some ideas on the go forward, we've got projects that we listed in the slide deck. I'll hit on a few of those just to give you some more color. First, one that I'm pretty excited about is our LOE optimization through condition-based maintenance. Over the last several years, Devon sought to really improve our reliability through planned maintenance, but a lot of that maintenance has been calendar-based to date. Equipment essentially gets maintained, whether it actually needs that maintenance at that time or not. What we are attempting to do there is use advanced analytics, KPIs, and move that essentially to condition-based maintenance with the idea that we can eliminate some of those ineffective or potentially wasteful maintenance activities. That will help us reduce on the LOE front. Another one I like to talk about is our smart gas lift calibration. Devon uses a lot of centralized gas lift in certain assets, predominantly in the state line area in the Delaware Basin and also in the Williston Basin. Sometimes these operations can be a little bit constrained on the gas lift injection. When that occurs, we have suboptimal lift occurring. This is a project that we are already advancing. We are looking to use real-time analytics and AI models essentially to determine how much gas to allocate to each well for optimal performance. Those recommended injection rates are pushed directly. Okay, I'll continue. These real-time analytics and AI models essentially determine how much gas to allocate to each well for optimal performance. Those injection rates are pushed directly to end device for adjustment. Where we have these big centralized gas lift operations, we expect to see some pretty significant uplift there. As opposed to the project that I described earlier, this largely comes in the form of lowering our downtime and flattening our base decline curve. It gives you a little flavor. We expect to see some of this on the LOE side and expect to see some of this through improved production, which would eventually come in the form of lower capital. Neil, are you still there? Thank you. Moving on to our next question, which comes from Arun Jayaram with JP Morgan. Please go ahead. Yeah, Jeff, just to follow up, I just wanted to see if you could just maybe clarify your comments on the lower GP&T rates in Delaware. Could you maybe give us a sense of what this would do to your broad GP&T cost per unit if we were to translate that into our models in 2026? Yeah, you better. Yeah, you better, Arun, just to give you a little bit additional color. As I said, it's really specific to our NGL business. There's some on the gas side as well, but that's where the biggest driver of this is. Just to give you a sense, we had some legacy contracts that were, call it $1.50 an M, and now they're going to be almost half of that, right, in some cases. It's going to be pretty material. Again, specific to the Delaware, not at a corporate level, but specific to the volumes in Delaware, it's going to be pretty material to our overall business. As we highlighted in the slide deck, $200 million of that is already locked up and captured. The team's working on the incremental, call it $50-$100 million over the course of the rest of this year. By the beginning of 2026, we should have that all locked down in good shape, and you'll start to see it flow through our financials. It'll come through our financials in two ways. One, you'll see lower GP&T cost, but you'll also see, just given the nature of some of those contracts, it'll show up in better realizations for us as well. A combination on the financial statement between realizations and our GP&T cost. Thanks, Jeff. You guys highlighted some divestitures, your interest in Matterhorn, and some real estate assets. I was wondering, Clay, if you could highlight some of your incremental midstream investments that you have at Devon that could be subject to future monetization. Yeah, thanks for the question, Arun. We have a lot of midstream assets in particular that hold various values to us. We've highlighted a few times the value that Grayson Mill brought along with the midstream assets and what that can mean to not just the individual well economics, but the increase related to the amount of portfolio options we have there. Sometimes it has really interesting and incremental value. I would say there's other parts of the midstream asset portfolio that we may question. Is this the right, is something for us to continue to hold on to? Without going into details one- for- one, I would just tell you we're taking a holistic look that maybe there's sometimes we need to expand our midstream footprint to replicate what we're doing there with the Grayson assets. I would say there are other times, for example, with Matterhorn, where it has kind of served its purpose. We continue to hold on to that capacity, which is incredibly valuable, but the equity ownership clearly was not reflected in our organizational value. Therefore, when we monetize, it is just additional cash. I would say there is more of that to come, but it is too early to tell which direction we are going to be going overall as a corporation. Thanks a lot. You bet. Thank you. The next question comes from Doug Leggett with Wolfe Research. Please go ahead, Doug. Once again, maybe the. Doug, your line is over. Please proceed with your question. We are getting no response from Doug's line. I'm moving on to our next question, which comes from Paul Cheng with Scotiabank. Please go ahead, Paul. Thank you. Hey, guys, can you hear me okay? Yeah, Paul, thank you. Hello? Okay, good. Two questions, please. First, I think Jeff and Clay, you guys talking about on the business optimization, seems like technology is going to be a big piece of that. Can you give us some understanding that, I mean, how that the adoption now you are doing is different than what you've been doing? Also, that how you are different from the rest of your peers in terms of the adoption of the technology. Can you give us some example that what's new adoption versus that what you guys have been doing? That's the first question. Second question is that when we're looking at these in our model, not like the Delaware Basin, comparing to the number of wells that you brought on, the production is a little bit light for us. Wondering that is there some one-off item other than, say, the winter storm? Is it the cadence of the well coming on stream throughout the quarter is different than a more variable or just back-end loaded? Any kind of maybe the colors that you can provide, that would be great. Thank you. Yeah, thanks, Paul. You know I love technology near and dear to my heart. One of the changes we made organizationally was promoting Trey Lowe, our Chief Technology Officer, to the executive committee. I think it is just already paying huge dividends, have a ton of faith in our organization's ability to embrace technology across the board. I would love for Trey to expand a little bit on some of the things that he sees, one as the leader of technology, but also the leader of our business optimization project. Definitely appreciate the question, Paul. We view technology as a differentiator for Devon, just as you highlighted. The ability for us to use technology to improve our operations is kind of core to our culture that we have here. The things that are new, John highlighted a couple in the production space that will be underpinned by new technologies that we have been investing in over the last few years. The other one that I would highlight is we have made a substantial investment in all of our industrial systems, sensors that we have across the field. We have invested heavily in standardizing that across all of our wells, thousands of wells that we have across the business. When you mix that with the competency that we have built in our teams and the alignment that we have across our leadership group to use that data, we are going to continue to see those advantages on the production space. One of the exciting projects that they have in our business optimization program is to take all of that real-time information and start running both physics-based models and algorithms in real time at scale across all of our wells to reach an optimal flowing condition for each well. We are going to see the implementation of that over the next year. That is a significant portion of that $250 million of targets that we have in the production optimization space. The second example that I love to talk about is AI and what we think that will mean for our company and for our employee base. This year, we have rolled out a brand new platform for all of our employees. Honestly, it has caught wildfire across our employees. We have seen productivity boosts from various domains up to 15%-30% on the projects that they are working on. These are real examples in our core business around things like how do you optimize Simulfrac on a well? Or how do you take mud logs and cutting descriptions and use AI to give you a better geologic answer? We are starting to see all of those things kind of flow through the company and that productivity boost for our employees. We are empowering a group of individuals that are already aligned to using these tools, and we are real excited about it. Paul, for your second question, John will pick that one up. Hey, Paul, to your question on the Delaware Basin, there are a few things I will highlight there. One, yes, from a gross well standpoint, we brought on quite a few wells in the Delaware Basin. We did have a little bit lower working interest in Q1. From a net wells perspective, we are pretty similar to what you saw in Q4. The second thing I would point to there is the cadence of those wells was later in the quarter, so you got less production contribution from those wells in the quarter. That is a little bit of the phenomenon you are seeing. You mentioned the weather. That was certainly a factor. We did see some minor weather downtime also in Q1 in the Delaware Basin. What I would tell you is from a well productivity standpoint, going back to Q4, what we're seeing in Q1, we're really pleased with what we're seeing, especially early time. Most all of our projects and our major programs are meeting to exceeding expectations. Despite what you're seeing, we're really, really pumped about what's going on in the Delaware. Thank you very much. Thank you. The next question comes from Scott Hanold with RBC. Please go ahead. Yeah, thanks. Good morning. Clay, maybe give your view on sort of the broad macro trends. A lot of your peers have made some cuts to their activity levels, bringing down production relative to prior expectations. I think part of the effort, too, is to continue to enhance free cash flow. Can you give us a sense of how you're looking and thinking about the macro? I mean, there were no specifically defined cuts related to weaker oil prices, but what would it take for Devon to sort of reevaluate its plan? Yeah, thanks for the question. Very topical today. Certainly, the macro environment is not lost on us. When we first think about the macro and we think about the commodity price and how it affects our investment decisions, we think about things through really kind of three lenses. One is the corporate break-evens, we mentioned earlier, $45 including our dividends. That's kind of one test. We think about the well returns, the economics, but we also think about the operational objectives and the associated distraction of making moves up and down, yo-yoing, essentially, the activity. All of the operational efficiencies we keep baking in quarter after quarter after quarter are on the back of that consistency. We do not take changes like that lightly. You've seen us gradually move down the rig count in the Delaware Basin, 16 projecting going down to 11 with a similar output, and that's incredible efficiency. As you mentioned, those are operational changes and not really a reaction to the macro. When I think about the macro today, the forward curve is relatively flat relative to the last couple of years, hovering around just under $60. We're watching that. We think about these incremental, these marginal investments really in the 12 month-24 month timeframe. When I look at that curve, it still passes the test. I can tell you, we're very self-aware. We're thinking about what's going on. We understand our flexibility. We reviewed all of our contracts. We have a tremendous amount of flexibility. I would say we're closer to taking those kinds of actions, but not quite there. I think when market gets a little closer to the low $50s and we feel like that has some sustainability, I think we'd be more likely to take more aggressive actions in addition to the maintenance capital node that we're in now. As for now, we'll take the operational improvements, accrue that to capital savings, continue to build free cash flow related to that. Then again, the business optimization is our incredible focus on driving more and more free cash flow, which we think has a tremendous amount of uplift for the organization and ultimately for the investors. That's on the back of some really focused work by the organization and not yo-yoing them around too much. Appreciate the comment. I think this one's for Jeff. You all have pegged roughly, what, $200 million-$300 million per quarter on stock buybacks. Obviously, related to everything we were just talking about, a lot of the equities in energy have come down quite a bit, including Devon as well. Given that you're pulling forward some of this optimization value and you've got, it sounds like, very good visibility on achieving it, does it make sense to maybe step up buybacks a little bit in the near term and utilize some of that free cash flow opportunistically? Yeah, Scott, thanks. I appreciate the question. Yeah, we've thought a lot about that and do consistently debate that with our board. Each quarter is based on the macro environment and our broader strategic objectives. At this point, we feel very committed in not changing our game plan. You're going to continue to see us execute on the $200 million-$300 million range of share repo each quarter. Obviously, the fixed dividends in place, we expect to grow that annually. Any incremental free cash flow that comes back to the balance sheet, we're going to use that to bolster our liquidity and ultimately pay down our debt over time. No change to our financial framework at this point in time. As Clay said, we're obviously not sticking our head in the sand. We're going to watch the market and adjust accordingly. We feel confident in our approach and do not have any plans to change that at this point. Thank you. Thank you. Our next question comes from Kalei Akamine with Bank of America. Please go ahead. Hey, good morning, guys. I want to follow up on the Permian Basin. In the first quarter, you had the bulk of the TILs in this year's program here in this quarter. I have to imagine that there's a few Wolf Camp B's in there. Can you talk about the productivity that you're seeing so far, i.e., how does it compare to tier one zones like the A bench? Are there any noticeable differences in the oil rates or in the oil and gas mix? Hey, Clay, this is John. What we're seeing right now from the Wolf Camp B is fairly consistent with our expectations. What I would tell you about the Wolf Camp B is you see a lot of variability in the oil cut or the oil production throughout the basin. When you think about our acreage footprint, we're quite diverse. We've got stuff up north in Eddy County, stuff up north up in Lea County. You go down to our state line area across the border, and you get a little bit different contribution across all those assets. I'd say as you go further to the north, we see quite a bit higher oil cut. You see production characteristics that are more aligned to the upper Wolf Camp. As you go south into the state line area, maybe over to our Monument Draw area, you see a little bit gassier type oil contribution, more consistent to a condensate play. I would say overall, what we are seeing, what we are bringing on from an oil standpoint is fairly consistent with our expectations. Got it. I appreciate that color, John. Maybe this one is for Clay. Clay, in your business improvement plan, there's a GP&T piece that you've kind of discussed here on this call. When you look at your position, particularly in the Delaware, do you see any other opportunities to remove fixed costs on the gathering and transportation side, maybe by buying in certain assets? Do you think this could be maybe a good use of the Matterhorn proceeds? Yeah, I think it's a great question. I'll go back to the comments around the earlier question about additional midstream actions. What I would say is, look, we're very objective about the value of midstream. Sometimes it accrues to the positive for us to own those assets. Sometimes it essentially has served its purpose, and it makes sense to liquidate those and redeploy those proceeds into something else. With Matterhorn specifically, that's above and beyond, as Jeff mentioned on his prepared remarks. That is not part of our business optimization proceeds. Those are above and beyond, go straight to the balance sheet and then preserve that liquidity for future use. I would say other assets, maybe they become more valuable in someone else's hands. We continue to have those conversations, remain objective about all of these midstream assets. I would tell you at this point, it could go either way from us adding more interest in some of these assets to liquidating, as we've done with some of those. You've seen us kind of see the benefit from both sides of that. We continue to explore all avenues to create incremental value for our shareholders. Got it. Thanks for that color, Clay. You bet. Thank you. The next question comes from John Freeman with Raymond James. Please go ahead, John. Thank you. I like the new presentation format that's in there. I was looking at slide four where y'all sort of showed the reinvestment rates you've had the last couple of years that kind of hovered around 60%. And I know in one key you got down to 50%, but just based on y'all's outlook for the rest of the year at $60 oil, it looks like it's implying you'll end up with kind of a pretty similar kind of reinvestment rate to what you've had the last couple of years, albeit at a more than $10 lower oil price. And I'm just trying to think about going forward, how important the reinvestment rate is when y'all come up with budgets. There's some of your peers that kind of target a reinvestment rate to get to their budget. Just maybe if you can kind of speak to that. Yeah, John, as you know, a lot goes into that, and it can move pretty dynamically with commodity price, with service costs. Obviously, as we're on John's team specifically, trying to drill the very best wells from the opportunities we have, just tweaks on completion design and productivity can also accrue to that as well. I think the reinvestment rate is a consideration, but it's not what we goal seek for on the overall budgeting. We keep an eye on that. We watch that. We certainly have an intended objective to stay in this range, but it's not necessarily the singular thing we're focused on when we're talking about capital allocation within the assets. Understood. My follow-up question, y'all highlighted during the quarter for Q2 at least that you're expecting $50 million of capital related to multiple land trades in the Delaware that's going to impact over 30 wells. Just curious if that's a renewed focus of the company or if this just was sort of a one-off or a few things kind of dominoed during this upcoming quarter. Yeah, John, thanks for noting that. I mean, this is awesome ground game work by the team. We hope to have more and more of this. This is trades, low-cost bolt-on acquisitions, really focused right ahead of the drill bit. Think of this. We're trading out of something that may be a longer-dated development for us. We're trading into something that we know is right in front of us. We're ready to drill. That has an incredible value creation uplift for us. Now, the challenge is in doing those trades, it also brings capital with it. It is a great point to highlight the $100 million of savings that we're talking about. Moving from a midpoint of 3.9 to a 3.8 is additional to this $50 million that you pointed out from these trades. That's capital that was drug into this year from some great work that the teams have done. Also, remember, as we move faster, we continue to drill faster, complete faster, that would normally bring in additional capital. I would say in years past, we've taken that, we've kind of accrued that benefit through the production side. Without any mitigation steps, that 3.9 would have moved to 4.0. With that extra 50, it would have been $4,050,000,000. What we're doing is we're moving from that point down to a midpoint of 3.8. It's really a change of about $250 million kind of point- to- point. Things like that we will continue to do. We're not always going to be able to do that level of scale, but remain very opportunistic. The team's doing a great job of looking for those trades. It brings back the dissolution of the BPX deal. That's $0 out the door, something we've been working on for a very long time, but accrues to a huge amount of value creation for the organization. We're looking for all of those things. That could be in the form of midstream. It could be in the form of asset trades or a number of things. This is what the business optimization is really on the back of, kind of where do we create value from all facets of the organization. I can tell you, it's really empowering to the organization. There's a lot of excitement around the organization from North Dakota to South Texas in a singular goal really being focused, and we're seeing a lot of momentum from this. Thanks, Clay. I appreciate it. You bet, John. Thank you. The next question comes from Betty Jiang with Barclays. Betty, your line is now open. Please go ahead. Hi, good morning. Thank you for taking my question. I want to go back to the cost optimization and maybe ask differently that there are just many moving pieces that manifest in the financials. It is clear that the benefit is going to accrue to a lower CapEx number. Between the efficiency gains, the production optimization, and maybe any leading-edge cost deflation that you're seeing in the market, how much could we see maintenance CapEx coming down over the next couple of years? Yeah, let me start that, and I'll hand it over to Jeff to give you a little bit more color. One, I appreciate the acknowledgment of these many moving parts. One of the things in Jeff's prepared remarks that he said, and I just want to underscore once more, we could be entering a period of deflation given rig drops and the macro environment. Those deflationary benefits that will accrue to free cash flow and accrue to our bottom line are not counted in this business optimization project. They will be in addition to. Our goal going forward on a quarterly basis will be an attempt to update the investors on this progress, trying to separate all the moving parts, commodity price and inflation, deflation, and all these other things. It is our commitment to you to make sure that you know this is above and beyond. We run this at a base mid-cycle price deck at the beginning of the guidance we provided, the 25 base plan. These other changes above and beyond that, one will either fall into the business development or, in the case of a deflationary benefit, that is separate and apart. Jeff, other comments? Yeah, Betty, I would try to put it as simply as this. We've got a base level 2025 baseline guide today of $3.8 billion. When you put together the capital efficiency and some of the corporate capital costs that we've highlighted in our business optimization plan, you get down to a maintenance number closer to kind of $3.4 billion-$3.45 billion, right, as it relates to the go forward maintenance capital for the company. That's when you fast forward to 2027, obviously, after we've done all this work and executed and delivered on these efficiencies. That is the kind of number that we're looking at and driving towards as we execute on this business optimization work and ultimately expect all things being equal, right? When we fast forward to 2027, that would be the kind of maintenance capital profile that we'd be looking to be delivering on going forward. All this effort around our business optimization is focused on driving that break-even that we talk about a lot lower in our business, right? At the end of the day, that's got to manifest in a lower maintenance capital level for us going forward. That's how we're thinking about it. One other thing I would just add to that. When you lower that break-even and you are not drawing on that portfolio quite as hard, in effect, the side benefit is you extend that portfolio even further. Again, lots of business opportunities. We are very focused on this. As I said, the organization's really fired up. There are so many additional benefits that the people sitting around this table can't see today and cannot even predict. That is where I get most excited is, when the organization just organically is wanting to be part of that, embracing technology, driving efficiencies, accruing that to value either through production or a lower cost structure, ultimately driving our maintenance capital down. As a side benefit, continuing to benefit our portfolio and extend the runway on it. Great. No, that's super helpful. Appreciate all that color. I understand the service cost deflation is really incremental. Maybe on my follow-up, Clay, you mentioned earlier that you're not looking to take more aggressive action unless prices go to the low 50s. I understand the momentum that you are seeing across all the basins. Permian, you're doing really well on efficiencies. You go further with the dissolution of the JV. Which asset do you think has more flexibility to slow down? I know it might be a more difficult question to answer right now, but would love to get some color on how you think about it. Betty, I appreciate the question. I talked about the three lenses and how we think about how are we investing, at what level do we invest, how do we allocate that capital amongst our businesses. I'll give you an interesting kind of parallel. In the Powder River Basin, it's some of the most challenging economics. Objectively, it's just earlier in its development. We're still working on driving down cost structure, increasing the productivity and the consistency, which we're seeing a lot of wins. That operational momentum that we've generated over the last few years has been on the back of one rig, okay? That is an area that probably, even though it's the most challenging on the single well rate of return, state of the art today, probably has the most upside potential from value creation for continuing to invest and assessing and understanding and really leveraging that incredible footprint that we have. There is a little bit of a resistance to hold back on that. I can tell you when you get into the low 50s, everything is again on the table. We need to make sure that we're doing the right thing for the organization. Contrast that with our highest rate of return, the Delaware Basin. You've seen us actually lower and flex the operations on it because we have the ability, the scale delivers to drop rigs, take a little bit more of a slower pace on some of the frac holidays that we're going to be baking in. That allows us to deliver incredible productivity for our crown jewel asset and do it in a paced way that extends that inventory even longer. It is a complicated answer. What I would say is we'll continue to evaluate. We have lots of options. We don' t have from years of the past, we are thinking about other burdens that we might have experienced a decade ago around long-term rig contracts or minimum volume commitments on pipes or trying to hold lease positions together. We are not burdened by any of that. We have a tremendous amount of flexibility. We are very objective about this, but we are also very thoughtful about the costs and the consequences to the operational improvements that we are making. Right now, we are really focused on driving the value through that lens. I appreciate all of that. Thank you so much. Thank you, Betty. Thank you. Our next question comes from Kevin MacCurdy with Pickering Energy Partners. Kevin, please go ahead. Hey, good morning, team. Clay, you kind of touched on this earlier, but just to confirm, you've lowered your average rig count in Delaware from 14 to about 12 this year. Your turn-in line count is still the same. Will that have any impact to your wells in progress at the end of the year or your ability to grow in 2026? We're very thoughtful about looking ahead to 2026 and any actions we take in 2025. Clearly, the spuds that we have for the balance of the year, essentially all of the value accrues to 2026. To hit the question on the head, we are not sacrificing 2026's productivity. We're doing this in a consistent approach. We're thinking about what maintenance capital looks like, continuing to invest in that. When we rewind back, the graphic actually shows not too long ago, we were running 16 rigs. Beginning of the year, we were 14. We expect to get to 11 rigs on the back of the same amount of productivity output. That accrues in a few different ways. We're drilling faster, much more efficiently. We've got the efficiency of the lateral length, how much productive lateral length we have, and then also the productivity of the wells continue to accrue to the upside. Some of the great work that John's team's doing, understanding that subsurface is highly valuable and critical, and that's where we create a tremendous amount of value. That's hard to put into a graphic form, but we're continuing to see the benefit there. Great. I appreciate the clarification on that. As a follow-up, as you look out on your portfolio, if oil prices continue to lag and gas stays strong, are there any areas where you would consider shifting activity towards or away from, just given commodity mix? Yeah, we're always taking that into consideration. We're pretty agnostic on where we create value, being which basin, which commodity. As the commodities move, you could even have inflation or deflation present in one basin relative to another. We certainly take all of that into account and regularly, essentially on a monthly basis, look to how we make those adjustments. Again, with the thinking in mind that we don't want to chase false positives or yo-yo the organization. Just in the last 24 months, we've seen all forms of commodity price, front month, contango, backwardation, and we've refused to kind of chase the false positive. This feels a little different. There's a lot more stickiness. There's probably a compounding effect of the headwinds. I would consider us essentially on high alert in regards to where commodity price is heading. Again, you're starting to see a flat curve, kind of reinforcing that this could be a little bit lower for longer. Again, we have the capabilities to step down activity. Consider us on high alert at this point. All right. Thank you. You bet. Thank you. Our next question comes from Matthew Portillo with TPH and Co. Please go ahead, Matthew. Good morning, all. I just wanted to unpack your capital allocation in the Rockies a bit. Looking at the program this year, I think the plan calls for about 70-75 gross wells in the Bakken. And in our math, that would probably translate to around $650 million-$700 million of capital. I was curious if that's a good number to think about for your Bakken program in 2025, and if you've been able to make any additional cost outs on the program since taking over the Grayson asset. Yeah, Matt, this is John. I think those numbers are still good. For total Rockies, we're targeting 80-90 wells. You're about right on what that's going to mean for the Williston Basin specifically. I'd say specific to Grayson, that integration continues to go great. We're continuing to see the synergies there, whether it be from refracts all the way to infrastructure and facilities. We've talked about a $600,000 well synergy there, I think, since the beginning. I've got Tom Hellman sitting next to me. I think it's a good opportunity for him to talk about some of the ongoing improvements that we've seen through the first quarter that might help you give a little bit better view of what's going on there. Yeah. Hey, Matthew, this is Tom. Drilling pace actually is up an additional 19% to the plan, and drill costs are down now 15%. We also have completion costs down an additional 8%. Yeah, as John said, on a per well basis, we're talking about an additional $600,000 to the plan. A lot of that's just really pushing the ROPs, working with Trace data and some real-time data, getting some record wells in the ground. On the completion side, we've gone to full Simulfrac and actually did a complete re-look at the completion design, and we went to 100 mesh and self-sourcing that. That was substantial savings on the completion side as well. Great. As my follow-up, I think the program for the full year in the Rockies was about $1 billion. It seems to leave about $300 million for the Powder on call at 15 wells-20 wells. I was curious if you might be able to just help us understand what might be driving the elevated capital in the play this year. Is that potentially a lever you could pull down into 2026 to improve your corporate capital efficiency until the macro environment improves? Yeah, Matt, I think my answer is going to be pretty consistent with what Clay talked about there. That Powder program this year at roughly 15 wells is entirely focused on the Niobrara. Clay talked about it being early innings in the play. Clay talked about there being significant upside in the play. Any kind of relative change in capital you've seen probably relates to that program being 100% focused on the Niobrara. With that, our objectives are pretty clear. We've got a little bit of appraisal work that we're doing to see if we can improve the productivity of those wells. Suffice it to say, we're also working with our consistent program to drive down cost. We've seen some really good benefits there. Obviously, what we see this year, and it is what Clay said on the macro, we will have to look and see next year, but those are our strategic objectives, at least for that program. Matt, we are going to have to follow up with you. We are not getting the same math on a per well that you were kind of pointing to. We will follow up with you after the call. I think roughly we are about $12 million or so per well. That is on an 8/8 basis. That is down from $15 million, and we have a line of sight vision to $11 million and below. My personal line of sight is below $10 million, just to let the teams know. We will continue to work that direction. That is on the back of a lot of great work from the organization, continuing to drive efficiencies, record-setting wells. Tom, what is the latest? $116 a foot. What does that translate into days for a three-mile well? Nine or ten days. Nine or ten-day three-mile wells in the Niobrara. Right about that one. That is pretty impressive. Again, more to come on that from a completion cost. It is a light infrastructure. We have very little localized infrastructure. We are doing things like investing in a sand mine so we can get our local cost down. We have built a recycle facility, so we dispose of no water in the basin. All of that goes back into frac water for the wells. Some of that costs money upfront. I am sure that some of that will be baked into these numbers you are talking about. Excited about where we go from here. Again, tremendous asset with lots of running room. Continue to run that. Everything is on the table as we move into a more distressed environment. Thanks so much. You bet. Thank you. Those are all the questions we have time for today. I'll turn the call back over to Rosy for closing remarks. Thank you. Excuse me. Thank you. Thank you for your participation in our call today and your interest in Devon. If you have additional questions, Chris and I are available. Please give us a call. Thank you, everyone, for joining us today. This concludes our call, and you may now disconnect your line.