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Operator: 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.

Rosy Zuklic: 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.

Clay Gaspar: 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 capturing 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 01, 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.

Jeff Ritenour: 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 $375,000,000. 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 cost, renegotiating contracts and reducing corporate cost. 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 pretax 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 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. 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 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 $1 billion 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, as the teams have proactively begun implementing many of these initiatives, we’re confident in our ability to achieve our targets and have clear line of sight to our objective.

With that, I’ll now turn the call back over to Rosy for Q&A.

Rosy Zuklic: 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.

Operator: Thank you. Your first question comes from Neil Mehta with Goldman Sachs. Neil, please go ahead.

Neil Mehta: 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.

Clay Gaspar: 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.

Jeff Ritenour: Yes, Neal, 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.

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

John Raines: Yes, Neal, thanks for the question. So, 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. [Technical Problem] Okay. So, I’ll continue with these. Real-time analytics and AI models essentially determine how much gas to allocate to each well for optimal performance. And so, those injection rates are pushed directly to end device for adjustment. So, again, where we have these big centralized gas lift operations, we expect to see some pretty significant uplift there. And 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.

So, 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.

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

Arun Jayaram: 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?

Clay Gaspar: 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 cost, 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 cost.

Arun Jayaram: 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?

Clay Gaspar: 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. And 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.

Arun Jayaram: Thanks a lot.

Clay Gaspar: You bet.

Operator: 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.

Paul Cheng: Thank you. Hey, guys, can you hear me okay?

Clay Gaspar: Yes, Paul.

Paul Cheng: 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.

Clay Gaspar: 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. And I think it’s just already paying huge dividends have a ton of faith and 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.

Trey Lowe: Definitely, I appreciate the question, Paul. We view technology as a differentiator for Devon just as you highlighted, and 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’ve been investing in over the last few years. The other one that I would highlight is we’ve made a substantial investment in all of our industrial systems, sensors that we have across the field. We’ve invested heavily in standardizing that across all of our wells — thousands of wells that we have across the business. And when you mix that with the competency that we’ve built in our teams and the alignment that we have across our leadership group to use that data, we’re 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. And so, we’re going to see the implementation of that over the next year, and that’s a significant portion of that $250 million of targets that we have in the production optimization space. And then 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. And this year, we’ve rolled out a brand-new platform for all of our employees. And honestly, it’s caught on like wildfire across our employees.

And so, we’ve seen productivity boost from various domains up to 15% to 30% on the projects that working on. And these are real examples in our core business around things like how do you optimize final frac on a well? Or how do you take mud logs and cutting descriptions and use AI to give you a better geologic answer. And so, we’re starting to see all of those things’ kind of flow through the company and that productivity boost for our employees, and we’ve been powering a group of individuals that are already aligned to using these tools, and we’re really excited about it.

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

John Raines: 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 put about what’s going on in the Delaware.

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

Scott Hanold: 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?

Clay Gaspar: 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. And 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 kind 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 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.

Scott Hanold: Appreciate the comment. And I think this one is for Jeff. You all have pegged roughly, what, $200 million, $300 million per quarter on stock buybacks. And obviously, related to everything we were just talking about. A lot of the equities and energy have come down quite a bit, including new Devon as well. given that you’re pulling forward some of this optimization value, 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?

Jeff Ritenour: Yes, Scott, thanks. I appreciate the question. And 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.

Scott Hanold: Thank you.

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

Kalei Akamine: 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?

John Raines: 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’ve got a step up north in Eddy County, step up North Lea County. You go down to our Stateline 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 Wolfcamp. And as you go south into the Stateline area, maybe over to our Monument Draw area, you see a little bit gassier type oil contribution more consistent to 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.

Kalei Akamine: 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. But when you look at your position, particularly in the Delaware, do you see any other opportunities to remove fixed cost on the gathering and transportation side maybe by buying in certain assets. And whether — and do you think this could be maybe a good use of the Matterhorn proceeds?

Clay Gaspar: 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. And 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 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. And 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. So, 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.

Operator: The next question comes from John Freeman with Raymond James. Please go ahead, John.

John Freeman: 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%. And I know in 1Q 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 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. And 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.

Clay Gaspar: Yes, 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 — and 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. So, 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.

John Freeman: Understood. And then my follow-up question, you all highlighted during in 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?

Clay Gaspar: Yes, 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 a trade low-cost bolt-on acquisitions, really focused right ahead of the drill bit. So, 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 and that has an incredible value creation uplift for us. Now the challenge is in doing those trades, it also brings capital with it. And so, it’s a great point to highlight the $100 million of savings that we’re talking about moving from a midpoint of $3.9 million to a $3.8 million is additional to this $50 million that you pointed out from these trades.

That’s capital that was drug into this year for some great work that the teams have done. And then 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. And so, without any mitigation steps, that $3.9 million would have moved to $4.0 million. And then with that extra $50 million, it would have been $4.50 billion. And so, what we’re doing is we’re moving from that point down to a midpoint of $3.8 million, it’s really a change of about $250 million kind of point to point. And so, 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 is 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. And 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. And 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.

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

Betty Jiang: 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.

Clay Gaspar: Yes. Let me start that and then 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, I just want to underscore once more, we could be entering a period of deflation, given rig drops in 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. And so, our goal going forward on a quarterly basis will be an attempt to update the investors on this progress trying to separate all of the moving parts, commodity price and inflation, deflation and all these other things, but it’s our commitment to you to make sure that you know this is above and beyond.

We run this at a base mid-cycle price stack at the beginning of — at the guidance we provided, the ’25 base plan and then these other changes above and beyond that, one, we’ll either fall into the business development or in the case of a deflationary benefit, that’s separate and apart. Jeff, other comments?

Jeff Ritenour: 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 get down to a maintenance number closer to kind of $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? And so, at the end of the day, that’s got to manifest in a lower maintenance capital level for us going forward. And so that’s how we’re thinking about it.

Clay Gaspar: And one other thing I would just add to that, when you lower that breakeven and you’re not drawing on that portfolio quite as hard, in effect, the side benefit is you extend that portfolio even further. So again, lots of business opportunities. We are very focused on this. As I said, the organization is really fired up. There’s so many additional benefits that the people sitting around this table are not going to — can’t see today and can’t even predict. And that’s where I get most excited is what the — when the organization just organically is wanting to be part of that embracing technology, driving efficiencies, accruing that to value either through production or lower cost structure, ultimately driving our maintenance capital down and as a side benefit continuing to benefit our portfolio and extend the runway on it.

Betty Jiang: Great. No, that’s super helpful. I appreciate all that color. And 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 has 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.

Clay Gaspar: Well, Betty, I appreciate the question. I was — 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 and I’ll give you an interesting kind of parallel? So, 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 in assessing and understanding and really leveraging that incredible footprint that we have.

So, there’s a little bit of 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 in 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, and 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. So, 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 in the past, we’re 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’re not burdened by any of that. So, we have a tremendous amount of flexibility. We’re very objective about this but we’re also very thoughtful about the costs and the consequences to the operational improvements that we’re making. And right now, we’re really focused on driving the value through that lens.

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

Kevin MacCurdy: 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?

Clay Gaspar: 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. And when we were 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.

And then also 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 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.

Kevin MacCurdy: 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?

Clay Gaspar: Yes. We’re always taking that consideration. We’re pretty agnostic on where we create value being Wish Basin, which commodity. And 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 yoyo 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.

And so, I would consider us on — 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.

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

Matthew Portillo: 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. And 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.

John Raines: Yes, Matt, this is John. I think those numbers are still good. We’re — 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. And 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.

Tom Hellman: 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%. And so, as John said, on a per well basis, we’re talking about an additional $600,000 to the plan. And 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. And 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 was substantial savings on the completion side as well.

Matthew Portillo: 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?

John Raines: 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. And so, any kind of relative change in capital you’ve seen probably relates to that program being 100% focused on the Niobrara. And so, 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. But 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.

Clay Gaspar: 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 on an 8/8 basis. 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. And so, 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?

Tom Hellman: $116 a foot.

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

Tom Hellman: 9 or 10 days.

Clay Gaspar: 9-day or 10-day 3-mile wells in the Niobrara, right about that one. That one is — that’s pretty impressive. And 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 — back into 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. And again, tremendous asset with lots of running room, continue to run that. But everything is on the table as we can move into a more distressed environment.

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

Rosy Zuklic: 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.

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