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 Investors 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, E&P 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 laws. 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 material. 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 3 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 fifty-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 breakeven, 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 '26. 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 4 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 $1 billion of free cash flow generated in Q1. With a 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 5, 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 6 and talk about the Eagle Ford. As announced last quarter, Devon and BPX 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 7, highlighting our first quarter financial performance. Devon's core earnings totaled $779 million or $1.21 per share, EBITDAX was $2.1 million, 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 return 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 8, 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 breakeven 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 to 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 to $3.9 billion. This reduction is driven by better performance on base and wedge production and the acceleration of capital efficiencies. Turning to Slide 9. 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 1 time. 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 return 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 on 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 in sustainable annual improvements by year-end 2026 as compared to our previously guided 2025 baseline. Beginning at the top with capital efficiency, we are targeting $300 million of improvements by year-end 2026. These capital enhancements are structural and assume steady service and supply costs. 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 costs. And finally, 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 the 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 of $1 billion pretax 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, as 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, 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.

Yes. Thanks so much. And let's start off with unpacking the cost reductions here on Slide 10 and eleven 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. So just kind of flesh it out a bit.

Yes. Thanks, Neil. Appreciate the question. What I would tell you is, so we've done a good job of pointing the 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 too. So, 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.

Yes, Neil, thanks for the question. Yes, I'm happy to jump in and talk a little bit about commercial opportunities. Frankly, that's where we have the absolute highest confidence because we already have those contracts executed. They are 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, so not a surprise to you, we have multiple midstream partners in the Delaware, in addition to the midstream infrastructure that we already own through our catalyst JV and our Cotton Draw midstream partnership. So that provides us a lot of leverage and opportunity and optionality, frankly to work with all of our partners and attempt to maximize margins. So, 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. So, it's a combination of lower fees, higher recoveries. The bulk of that is related to NGLs, our NGL business in the Delaware. But bottom line, we've reduced our fees. In some cases, we had legacy contracts that were 2x of what we expect to move forward with going forward. So, we've managed to reduce our fees on the gathering processing, transportation, and fractionation. And again, all that will take effect at the beginning of 2026. So, feel really confident in our ability to deliver on those outcomes.

Hey, Neil, in addition to that, John is here. He can talk a little bit about some of the opportunities in the production optimization.

Yes, Neal, 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. And so 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. So 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. So, equipment essentially gets maintained whether it actually needs that maintenance at that time or not. And so, what we're attempting to do there is use advanced analytics, KPIs and move that essentially to condition-based maintenance. So, the idea that we could eliminate some of those ineffective or potentially wasteful maintenance activities. And so, that will help us reduce on the LOE front. Another one I'd like to talk about is our smart gas lift calibration. Devon uses a lot of centralized gas lift in certain assets, predominantly in the Stateline area, in the Delaware Basin and also in the Williston Basin. And sometimes these operations can be a little bit constrained on the gas lift injection. And so, when that occurs, we've got suboptimal lift occurring. And so, this is a project that we're already advancing. We're 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 fixed directly.

Neil, are you still there? Thank you. Moving on to our next question, which comes from Arun Jayaram with JPMorgan. Please go ahead.

Yes. Jeff, just a follow-up. I just want to see if you could just maybe clarify your comments on the lower GP&T rates in the 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?

Yes, you better, Rune. 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, $1.5 and M, and now they're going to be almost half of that, right, in some cases. So, it's going to be pretty material. Again, specific to the Delaware, not at a corporate level, but specific to the volumes in the Delaware, it's going to be pretty material to our overall business. And as we highlighted in the slide deck, $200 million of that is already locked up and captured. And then the team is working on the incremental, call it, $50 million to $100 million over the course of the rest of this year. So, by the beginning of 2026, we should have that all locked down and in a good shape. And you'll start to see it flow through our financials. It will come through our financials in two ways. One, you'll see lower GP&T costs, but you'll also see, just given the nature of some of those contracts, it will show up in better realizations for us as well. So, a combination on the financial statement between realizations and our GP&T costs.

Thanks, Jeff. You guys highlighted some divestitures, your interest in Matterhorn and some real estate assets. Just wondering, Clay, if you could highlight some of your incremental midstream investments that you have at Devon that could be subject to future monetization?

Yes. 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 Mills 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. And so 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. And I would say there's other times, for example, with Matterhorn, where it's kind of served its purpose. We continue to hold on to that capacity, which is incredibly valuable, but the equity ownership clearly wasn't reflected in our organizational value. Therefore, when we monetize, it's just additional cash. So, I would say there's more of that to come, but it's too early to tell which direction we're going to be going overall as a corporation.

Thanks a lot.

You bet.

Thank you. The next question comes from Doug Leggate with Wolfe Research. Please go ahead. Doug, your line is open. Please proceed with your question. We are getting no response from Doug's line. And so, 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?

Yes, 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, then? I mean, how that the adoption now you are doing is different than what you've been doing? And also, that how you are different from the rest of your peers in terms of the adoption of the technology? And 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 this in our model, not like the Delaware Basin, comparing to the number of wells that you bought on, the production is a little bit light for us wondering that is there is some one-off item other than, say, the winter storm, is it the cater of the well coming on stream throughout the quarter is different than a more real one is back-end loaded? Any kind of maybe the colors that you can provide, that would be great.

Yes. Thanks, Paul. I love technology near and dear to my heart. And one of the changes that we made organizationally was promoting Trey Lowe, our Chief Technology Officer to the Executive Committee. I think it's just already paying huge dividends. I have a ton of faith in our organization's ability to embrace technology across the board. But I'd 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.

Thank you for the question, Paul. We see technology as a key differentiator for Devon, as you mentioned, and leveraging technology to enhance our operations is central to our culture. John pointed out a few recent advancements in production that are supported by the new technologies we've been investing in over the past few years. Additionally, we've made significant investments in our industrial systems and sensors across our fields, standardizing this technology across all of our thousands of wells. This, combined with the expertise built within our teams and the alignment of our leadership to utilize this data, will help us maintain our advantages in production. One exciting initiative in our business optimization program involves using real-time data to apply physics-based models and algorithms at scale across our wells to determine each well's optimal flow conditions. We will see this implemented over the next year and it forms a substantial part of the $250 million targets we have set for production optimization. Another example I'm enthusiastic about is AI and its potential benefits for our company and employees. This year, we've introduced a new platform for all our staff, which has rapidly gained popularity. We have observed productivity increases of 15% to 30% in various projects. These improvements are evident in our core business, including optimizing the final frac on a well and using AI to enhance geologic insights from mud logs and cutting descriptions. We are beginning to witness these improvements across the company, significantly boosting productivity for our employees, and we have a dedicated group ready to utilize these tools. We're truly excited about it.

And then, Paul, for your second question, John will pick that one up.

Hey, Paul, your question on the Delaware Basin, there's a few things I'll 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. So, from a net wells’ perspective, we're 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, and that's a little bit of the phenomenon you're seeing. You mentioned the weather. That was certainly a factor. We did see some minor weather downtime also in Q1 in the Delaware Basin. But 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. So, despite what you're seeing, we're really pleased about what's going on in the Delaware.

The next question comes from Scott Hanold with RBC. Please go ahead.

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. And I think part of the effort to is to continue to enhance free cash flow. Can you give us a sense of like 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?

Yes. Thanks for the question. Very topical today. And 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 breakeven as 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. So, we don't 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. But 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 to 24-month time frame. When I look at that curve, it still passes the test. But 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. And 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 mode 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. And 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, and that's on the back of some really focused work by the organization and not yo-yoing them around too much.

I appreciate your comment. I believe this question is for Jeff. You have estimated around $200 million to $300 million per quarter for stock buybacks, which relates to our previous discussion. Many equities and energy prices have decreased significantly, including new Devon. Since you are advancing some of this optimization value, it seems you have strong visibility on achieving it. Would it be wise to consider increasing buybacks in the short term and make use of some of that free cash flow strategically?

Yes, Scott, thanks. I appreciate the question. Yes, we 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 to not changing our game plan. So, you're going to continue to see us execute on the $200 million to $300 million range of share repo each quarter. Obviously, the fixed dividend is in place, we expect to grow that annually. And then any incremental free cash flow that comes back to the balance sheet, we're going to use that to bolster our liquidity and then ultimately pay down our debt over time. So, no change to our financial framework at this point in time. As Clay said, we're obviously not sticking our head and saying, we're going to watch the market and adjust accordingly. But we feel confident in our approach and don't have any plans to change that at this point.

Our next question comes from Kalei Akamine with Bank of America. Please go ahead.

Good morning, guys. I want to follow up on the Permian Basin. In the first quarter, you had the bulk of the till of in the year's program here in this quarter. And I have to imagine that there's a few Wolfcamp Bs in there. Can you talk about the productivity that you're seeing so far? i.e., how does it compare to Tier 1 zones like the A bench? And are there any noticeable differences in the oil rates in the oil and gas mix?

Hi, Kalei, this is John. What we're seeing right now from the Wolfcamp B is fairly consistent with our expectations. What I would tell you about the Wolfcamp B is you see a lot of variability in the oil cut or the oil production throughout the basin. And so, when you think about our acreage footprint, we're quite diverse. We got a step up north in Eddy County, step up North Lea County. You go down to our Stateline area across the border. 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 Wolfcamp. As you go south into the Stateline area, maybe over to our Monument Draw area, you see a little bit of a gassier type oil contribution more consistent with a condensate play. But I'd say overall, what we're seeing, what we're bringing on from an oil standpoint is fairly consistent with our expectations.

I appreciate that insight, John. Clay, regarding your business improvement plan, you mentioned a GP&T aspect earlier in the call. Considering your position, especially in Delaware, do you identify any other opportunities to cut fixed costs in gathering and transportation, possibly by acquiring certain assets? And do you think this might be a good utilization of the Matterhorn proceeds?

Yes, I think it's a great question, and 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 goes straight to the balance sheet and then preserves 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 and 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, and we continue to explore all avenues to create incremental value for our shareholders.

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 just looking at Slide 4, where you all sort of show that the reinvestment rates you've had the last couple of years have kind of hovered around 60%. I know in Q1 you got down to 50%, but just based on your outlook for the rest of the year at, call it, $60 oil. It looks like it's implying you'll end up with kind of a pretty similar kind of reinvestment rates what you've had the last couple of years, albeit at a more than $10 lower oil price. I'm just trying to think about like going forward, like how important the reinvestment rate is when you all come up with budgets. There are 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.

Yes, John, as you know, many factors influence that, and it can fluctuate significantly with commodity prices and service costs. As we work to drill the best wells from our available opportunities, adjustments in completion design and productivity can contribute as well. While the reinvestment rate is an important factor, it is not our primary target for overall budgeting. We monitor it closely and have a goal to maintain it within a certain range, but it is not the only focus when discussing capital allocation for our assets.

Understood. And then my follow-up question, you 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 and just curious if that's like a renewed focus for the company? Or is this just sort of a one-off or a few things kind of dominate during this upcoming quarter?

Yes, John, thanks for mentioning that. This is excellent work by the team on the ground. We aim to have more opportunities like this. This involves low-cost bolt-on acquisitions that are directly aligned with our drilling activities. Essentially, we are transitioning from a longer-term development project to something that is immediately actionable. We are prepared to drill, which brings significant value creation for us. The challenge with these transitions is the accompanying capital requirements. It's important to point out the $100 million in savings we anticipate as we adjust from a midpoint of $3.9 million to $3.8 million, in addition to the $50 million savings from these trades. This represents capital that we've brought into this year thanks to our team's efforts. As we enhance our pace of drilling and completion, we typically generate additional capital. In previous years, we have captured this advantage through production. Without any countermeasures, the $3.9 million would have increased to $4.0 million, and with the added $50 million, it would have reached $4.50 billion. Instead, we are adjusting down to a midpoint of $3.8 million, a reduction of about $250 million from point to point. We will continue pursuing similar opportunities, though we may not always achieve that scale. The team is effectively seeking out these trades. Additionally, the dissolution of the BPX deal is noteworthy; we let that go, which we had been working on for a long time, but it opens up a considerable amount of value for the organization. We are exploring all potential avenues, whether in midstream or asset trades, striving for business optimization to maximize value across the organization. It’s truly motivating for the organization, generating excitement from North Dakota to South Texas as we focus on a unified goal, and we are experiencing substantial momentum from this.

The next question comes from Betty Jiang with Barclays. Betty, your line is open. Please go ahead.

Good morning, thank you for taking my questions. I want to go back to the cost optimization. And maybe asked differently, that there are just many moving pieces that manifest in the financials. But it's 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.

Yes. I'll begin, and then I'll pass it to Jeff for additional insights. I appreciate the recognition of the various factors at play. I want to emphasize something that Jeff mentioned in his prepared remarks: we may be entering a deflationary period due to decreases in the macro environment. The benefits of this deflation, which will positively impact our free cash flow and bottom line, are separate from the business optimization efforts and will be in addition to them. Moving forward, we aim to provide quarterly updates to investors on our progress while clarifying the various factors involved, including commodity prices and inflation or deflation. We are committed to ensuring that you understand these benefits are incremental. We operate on a base mid-cycle pricing structure in the guidance we provided for the '25 base plan, with other changes being extra. Jeff, do you have any additional comments?

Yes. 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 capital efficiency and some of the corporate capital costs that we've highlighted in our business optimization plan, we get down to a maintenance number closer to $3 million, $4 million, $3 million, $4.5 million, 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. But that's 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 look to be delivering on going forward. All this effort around our business optimization is focused on driving that breakeven 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.

I would also like to mention that by lowering the breakeven point and not relying as heavily on that portfolio, we effectively extend its lifespan. This opens up numerous business opportunities, and we are very focused on this. The organization is highly motivated, and there are many additional advantages that may not be immediately visible or predictable. What excites me most is when the organization naturally embraces technology, enhances efficiencies, and converts that into value, either through increased production or reduced costs. Ultimately, this will lead to a decrease in maintenance capital while benefiting our portfolio and extending its viability.

Great. No, that's super helpful. I appreciate all that color. I understand the cost, 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. And just acknowledging the momentum that you're seeing across all the basins, Permian, you're doing really well on efficiencies. You go for with the dissolution of the JV. Like where which assets do you think have more flexibility to slow down? And 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.

Thank you for the question, Betty. I discussed our investment approach and how we allocate capital across our businesses. To give you an example, in the Powder River Basin, the economics are quite challenging as it's still in the early stages of development. We're focused on reducing costs and enhancing productivity and consistency, and we're seeing significant progress. This operational momentum has been achieved with just one rig. Although this area presents the toughest single well rate of return, it also has significant upside potential for value creation through continued investment and leveraging our strong position there. However, we are cautious and will reevaluate as prices approach the low $50s, ensuring that our actions align with the organization's best interests. In contrast, the Delaware Basin has the highest return rates. We have the flexibility to adjust operations, including reducing rig counts and pacing our fracking schedules, which allows us to maintain high productivity and extend our inventory. This is a complex situation, and we will continue to evaluate our options. In previous years, we faced burdens like long-term rig contracts and minimum volume commitments that constrained our flexibility, but we're no longer hindered by those issues. Instead, we have considerable flexibility and are being very thoughtful about costs and the impacts of our operational improvements as we focus on driving value.

Our next question comes from Kevin MacCurdy with Pickering Energy Partners. Kevin, please go ahead.

Good morning, Clay. You kind of touched on this earlier, but just to confirm, you've lowered your average rig count in the 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 '26 and any actions we take in '25. Clearly, the spuds that we have for the balance of the year, essentially all of the value accrues to '26. So, to hit the question on the head, we are not sacrificing '26 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 wind back, the graphic actually shows not too long ago we were running 16 rigs. Beginning of the year, we were 14, and we expect to get to 11 rigs on the back of the same amount of productivity output. So 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. The productivity of the wells continue to accrue to the upside. Some of the great work that John's team is doing understanding that subsurface is highly valuable and critical. 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. And 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?

Yes, we always take that into consideration. We're quite flexible regarding where we create value, whether it's in Wish Basin or any other commodity. As commodity prices fluctuate, we might experience inflation or deflation in one basin compared to another. We assess all of this regularly, typically on a monthly basis, to make necessary adjustments. We aim to avoid chasing false trends or causing instability within the organization. Over the past 24 months, we've encountered various commodity price scenarios, including contango and backwardation, and we have chosen not to react to false signals. This situation seems a bit different, as there appears to be more stability, and the challenges seem to be compounding. We are closely monitoring the direction of commodity prices. The emergence of a flat curve suggests that prices may remain lower for an extended period. We have the ability to reduce activity if needed. Please consider us to be highly vigilant at this stage.

Our next question from Matthew Portillo with TPH. Please go ahead, Matthew.

Good morning, all. I just wanted to unpack your capital allocation, the Rockies a bit. Looking at the program this year, I think the plan calls for about 70 to 75 gross wells in the Bakken. In our math, that would probably translate to around $650 million to $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.

Yes, Matt, this is John. I think those numbers are still good. For total Rockies, we're targeting 80 to 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 refracs all the way to infrastructure and facilities. We've talked about a $600,000 a 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.

Yes. 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%. So, 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 T data and some real-time data, getting some record wells in the ground. On the completion side, we've gone to full simul-frac and actually did a complete relook at the completion design, and we went to 100 mesh and self-sourcing that. So, there were substantial savings on the completion side as well.

Great. And then as my follow-up, I think the program for the full year in the Rockies was about $1 billion. That seems to leave about $300 million for the powder on, call it, 15 to 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? And is that potentially a lever you could pull down into 2026 to improve your corporate capital efficiency until the macro environment improves?

Yes, 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. And so, 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. Suffice it to say, we're also working with our consistent program to drive down cost, and we've seen some really good benefits there. Obviously, what we see this year and as what Clay said on the macro, we'll have to look and see next year, but those are our strategic objectives at least for that program.

And Matt, we're going to have to follow up with you. We're not getting the same math on a per well that you were kind of pointing to. So, we'll follow up with you after the call. I think roughly, we're about $12 million or so per well. That's down from 15, and we have a line of sight vision to 11 and below. My personal line of sight is below 10, just to let the teams know. We'll continue to work that direction, but that's on the back of a lot of great work from the organization, continuing to drive efficiencies, record-setting wells. Tom, what's the latest?

$116 a foot.

And what does that translate into days for a 3-mile well?

9 or 10 days.

9-day or 10-day 3-mile wells in the Niobrara, right about that one. That's pretty impressive. Again, more to come on that from a completion cost. It's a light infrastructure. We have very little localized infrastructure. So, we're doing things like investing in a sand mine so we can get our local cost down. We've built a recycled facility. So, we disposed of no water in the basin. All of that goes back to frac water for the wells. Some of that cost money upfront. I'm sure that some of that will be baked into these numbers you're talking about, but 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 can move into a more distressed environment.

Those are all the questions we have time for today. And so, I'll turn the call back over to Rosy for closing remarks.

Thank you, and thank you for your participation in our call today and your interest in Devon. If you have additional questions, Chris and I are available, so please give us a call.

Thank you, everyone, for joining us today. This concludes our call, and you may now disconnect your line.