Devon Energy Corporation (NYSE:DVN) Q4 2024 Earnings Call Transcript

Devon Energy Corporation (NYSE:DVN) Q4 2024 Earnings Call Transcript February 19, 2025

Operator: Welcome to Devon Energy Corporation’s Fourth Quarter 2024 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 Rosy Zuklic, Vice President of Investor Relations. You may begin.

Rosy Zuklic: Morning, and thank you for joining us on the call today. Last night, we issued Devon Energy Corporation’s fourth 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 Energy Corporation website. Joining me on the call today are Rick Muncrief, President and Chief Executive Officer; Clay Gaspar, Chief Operating Officer; Jeff Ritenour, Chief Financial Officer; John Rains, SVP, Asset Management; Tom Hellman, SVP, EMP Operations; and Trello, SVP, Technology and Chief Technology Officer. As a reminder, this conference call will include forward-looking statements as defined under US 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 materials. With that, I’ll turn the call over to Rick.

Rick Muncrief: Thank you, Rosy. Appreciate everyone taking the time to join us this morning. I’m very proud to report that Devon Energy Corporation ended 2024 with exceptionally strong results. Let’s start with slide two. We had outstanding operational performance, which underpinned the robust financial outcomes and significant free cash flow generation. This success is a testament to the dedication and hard work of our entire team. We produced record volumes, delivered a 154% proved reserve replacement ratio, and made nice strides on continuing our resource assessment of our existing assets. We generated $3 billion of free cash flow, of which we returned $2 billion to our shareholders. Consistent with our strategic priority of delivering value to shareholders through a sustainable, annually growing fixed dividend, this month, our board approved an increase to $0.24 per share.

This represents a 9% improvement over the 2024 rate. To fortify our managed portfolio even more, we executed the Williston Basin acquisition this past year, and it is performing quite nicely. Throughout the year, we’ve maintained financial strength, with ample liquidity and low leverage. We’re well-positioned for the future. You’ll hear more details from Clay and Jeff in a few moments. For me, it’s been an honor to lead this company for the past four years, serving our shareholders, our board of directors, and our dedicated employees. Together, we’ve built a very strong company with a solid foundation for the future. I want to thank everyone for their trust and support. I look forward to watching the company’s continued achievements under Clay’s capable leadership and have complete confidence in him and his management team.

I look forward to the many organic catalysts they will continue to create while remaining true to Devon Energy Corporation’s values and remaining focused on its strategic priorities. With that, I’ll now turn it over to Clay.

Clay Gaspar: Thank you, Rick. Always appreciated your guidance, mentorship, and insight, and I’m truly grateful for your confidence. Good morning, everyone. Let’s start on slide three, where I can cover the outstanding fourth quarter results. For the fifth quarter in a row, we have again beaten consensus and delivered outsized returns to our shareholders. First, fourth quarter oil production reached an all-time high of 398,000 barrels per day. Fourth quarter production outperformance was largely driven by the timing and productivity of our Eagle Ford wells. A second major contributor was from the acquired Grayson Mill assets, confirming how well that integration is going. The newly combined Rockies team is doing a fantastic job of learning from each other and creating additional value.

From a capital perspective, we also had an outstanding quarter. This performance was primarily driven by the good work of the Delaware team. In addition, lower workover costs combined with higher volumes drove our per-unit expenses significantly lower, boosting our margins and free cash flow generation. Thanks to our strong operating performance, we generated $738 million in free cash flow, of which we returned $444 million to shareholders via our fixed dividend and share repurchase program. We strongly believe that Devon Energy Corporation presents a compelling investment opportunity, and thus we leaned into our share repurchase program this quarter, buying $300 million of Devon Energy Corporation stock. Additionally, we strengthened our financial position by building cash this quarter to about $850 million, up 25% from last quarter.

Now let’s turn to slide four to talk about some of the exciting news related to the Eagle Ford. On January 31st, Devon Energy Corporation and BPX signed an agreement to dissolve our partnership in the Blackhawk field. We expect to close on April 1st, at which time we will hold approximately 46,000 Blackhawk net acres with greater than 95% working interest in these assets, primarily in DeWitt County. This will be a high-quality, high-working interest, fully controlled, and concentrated position. After close, we will have approximately 700 undrilled locations remaining in the Eagle Ford, 550 of which will be in the Blackhawk field. This is nearly a decade of drilling inventory at the current pace. A key value driver for us to dissolve this JV was that we are confident that we can save more than $2 million in D&C costs per well with improved well design, supply chain, and application of operational technology from our other basins.

The combination of this cost reduction and control of the go-forward development significantly enhances returns and provides a of our position. Now let’s turn to slide five and talk about the updated and improved 2025 outlook. Moving forward, we remain committed to creating value for our shareholders with disciplined investment and growth on a per-share basis. You should also note that we’re bumping our 2025 production and reducing our capital from the soft guide that we provided on the last call. We now expect to deliver 815,000 BOE per day, including 383,000 barrels of oil per day. For capital, we expect to invest $3.9 billion, or $200 million lower than the soft guidance we provided back in November. We expect these improvements to drive more than $300 million in additional free cash flow this year.

As displayed on the right side of the slide, these numbers add up to very impressive capital efficiency as compared to our peers in this highly competitive industry. Turning to slide six, let’s discuss the 2025 outlook from an asset perspective. The Delaware Basin will account for greater than 50% of our total investment for the year. We expect another year of strong performance and plan to operate 14 rigs and three completion crews while bringing online about 265 gross wells. As we have touched on in the past, we are leaning into a higher allocation of multi-zone projects as compared to historical levels, allowing us to balance rate of return, NPV, and inventory. Based on the success of 2024, we see tremendous benefits from the multi-zone developments by minimizing depletion effects between depleted dependent zones, feathering in de-risk secondary targets, and results that yield a more robust and sustainable inventory over time.

An area that I’ve been extremely impressed with is our ability to continue to find ways to accelerate our operational efficiencies. In 2024, we saw about a 15% improvement in both our feet drilled and completed feet per day metrics. This operational efficiency drives higher well returns and free cash flow generation. For 2025, I expect this momentum to continue, and I’m excited to see additional value creation from this work. Shifting to the Rockies, we possess a unique combination of assets that can provide growth and free cash flow. Approximately three-fourths of the Rockies capital spend will be directed towards the Williston Basin. With the impressive results to date, strong progress on the integration, and a long inventory runway, most of the capital will be focused on the western part of the Williston Basin.

We believe that this three-rig program balances flat production, impressive returns, and impressive inventory life. Since taking over the Grayson Mill asset, the organization has identified many opportunities to further enhance our investment. In just a few months since closing, we’ve already identified $50 million in capital and expense savings for the year, fully capturing our announced synergy target. We’re not done and expect additional savings on operating expenses as well as capital savings. The early wins of $600,000 in savings per well on D&C cost tie back to the drilling and completion pace, supply chain wins, and leveraging operational improvements such as self-sourcing sand and simul-frac. In the Anadarko Basin, the past few years have benefited from the Dow JV, which was set to end mid-2025.

With the success of this partnership, we have agreed to extend the JV for another 49 drilling locations for $40 million in drilling carry. Activity for the new agreement is planned to start in the second quarter of this year. Turning to slide seven, and before I hand the call off to Jeff, I want to address a common question that I’ve been asked since the leadership change was announced. And that is, what will be different for Devon Energy Corporation going forward? If I had to capture the transition in two words, it would be continuity and opportunity. As many of you know, Rick and I have worked together for over ten years and come from a similar background. Together, we built a strong foundation for Devon Energy Corporation, and we’re both excited about the next chapter for this great company.

Under continuity, I see continuing to focus on the following. First, Devon Energy Corporation’s strategic priorities and values will continue to be central for the company. Second, operating excellence will remain foundational. In order to succeed in this industry, we must deliver on the fundamental aspects of how we convert resources to value. And third, we remain committed to delivering value to our shareholders and maintaining a fortress balance sheet. We will continue to deliver a sustainable, growing fixed dividend, as well as executing on our share repurchase program. As far as the opportunity, I see several needle-moving prospects. First, we will focus inward to further improve our capital efficiency and margin expansion. Second, we will enhance our base production and organically expand our deep inventory.

Third, we will further embrace our value-creating technology across the company and promote innovative thinking from our outstanding employees. We are already working on several value-focused opportunities, and you’ll hear more about them in the coming quarters. With that, I’ll now hand the call over to Jeff.

Jeff Ritenour: Thanks, Clay. Moving now to slide eight to talk about our gas portfolio. With upward momentum in natural gas pricing, we see significant upside from our resource and wanted to highlight the value potential of our diverse portfolio. Although today our capital is largely allocated to oil projects driven by returns, the associated gas production and untapped natural gas resource underlying our acreage position provide a significant upside opportunity. As highlighted on the slide, we produce more than 1.3 billion cubic feet per day of natural gas, and with the move higher in pricing, natural gas revenue will more than double year over year. With the majority of gas production residing in the Delaware, our marketing team has done an exceptional job of diversifying our exposure to maximize value.

Through a variety of arrangements, a large portion of our Delaware gas has access to Gulf Coast markets and pricing, driven by growing industrial and LNG demand. For the remaining Delaware production exposed to in-basin pricing, we’ve utilized regional basis swaps for protection. This strategy helps us mitigate risk and stabilize our revenue streams. In the Anadarko Basin, our gas has access to southeastern markets, which have recently traded at a premium to Henry Hub prices as more and more companies point their molecules to the Gulf Coast. We expect increased demand for our gas in the southeast as the need for power moves higher in this growing region of the country. And we’re always looking for new demand outlets for our natural gas volumes.

We have an experienced and innovative marketing team that is actively assessing LNG, power producer, and data center supply opportunities. We look forward to sharing specifics on these opportunities as they develop and firm up over the coming year. To summarize, while our primary focus remains on oil, our gas portfolio offers significant optionality and value. Our marketing and risk management efforts ensure that we’re well-positioned to capitalize on growing demand and favorable market conditions. Turning to slide nine, as Clay said earlier, there’s no change in our commitment to delivering value to shareholders and maintaining our financial strength. For 2025, we’re targeting up to a 70% cash return payout to shareholders from generated free cash flow at current strip pricing.

Our cash returns will be delivered via our growing fixed dividend and share repurchases. Effective in the first quarter, the quarterly dividend is increasing to $0.24, and we expect a cadence of about $200 million to $300 million a quarter for share repurchases throughout the year. The balance of our free cash flow will accrue to the balance sheet for further debt paydown as we aim to drive our net debt to EBITDA ratio below one times and build upon our investment-grade financial strength. With that, I’ll now turn the call back to Rosy for Q&A.

Rosy Zuklic: Thanks, Jeff. We ask that everyone limit yourself to one question and one follow-up. So, Emily, we are ready to take our first question.

Q&A Session

Operator: Thank you. If you would like to ask a question, please press star one on your telephone keypad. Our first question comes from Scott Hanold with RBC. Please go ahead. Your line is now open.

Scott Hanold: Yeah. Thanks. Hey, guys. Strong quarter and, you know, Rick, congrats on the retirement and Clay on the promotion. You know, maybe I’m gonna start with, you know, the Grayson Mills seems like there’s been some strong outperformance here, you know, over the last couple of quarters, and it seems like you’ve got a lot of focus on that asset here in 2025. Could you remind us of the inventory duration you see within the Grayson Mill asset and sort of, you know, how that compares with your sort of legacy, you know, box?

Clay Gaspar: Yes, Scott. Thanks for the kind words. It’s a great time for Devon Energy Corporation, and I know Rick and I are fully aligned on the best times are still yet ahead. Specifically, Grayson, I think this is an important acquisition for Devon Energy Corporation to just absolutely stick. You know, when I think back on our portfolio pre-Grayson, we had a hole in the portfolio. We were not shy about admitting that. We have a great Williston team. We’re really excited about the brand that we had built within that Basin and what it could allow us to do, but, objectively, we were just short on inventory. Grayson really filled that inventory and, you know, secondarily, we needed to absolutely nail the execution. And so we’ve done that.

We’ve seen costs come down. We’ve seen that productivity stay up. What we’ve guided the street towards is we’re not gonna run at the same pace as the previous Grayson team. So we’ll see that productivity, excuse me, the production and absolute rate come down a little bit over time. What we’ve seen from both the cost side and the productivity side is that base decline has flattened out. These productivity of these wells have continued to improve, and now what we’re saying is this runway, that run rate that we are experiencing today is, we think, much more sustainable at the level we’re at, and that runway continues to expand. There’s more organic things to do, trades, you know, zero-cost opportunities to further expand that runway. But we’re approaching close to a decade of opportunity in the Williston Basin now, including Grayson.

So we’re really excited about where that position fits in our portfolio.

Scott Hanold: Appreciate that. And to my follow-up question, it’s gonna be on the Eagle Ford, you know, split with BPX. Could you give us a little bit of color on some of the background, you know, regarding that, you know, how did you all think about splitting the assets, and did you guys, I guess, look for more inventory versus PDP? Could you just tell us how that allocation back and forth went?

Clay Gaspar: Yeah. It’s interesting. I mean, I think this is a classic win-win. You know, when I summarize it and we display the map, when you think about the assets that BPX is gonna inherit and then the assets that we, objectively, they valued more of those assets, and we have valued more of the assets that we’re gonna inherit. And so there was a natural accretion associated with this deal. I think above and beyond that, I think about our ability to control pace, to really direct the operations. And then, as I pointed out in the prepared remarks, we see material operational improvement. We’ve already displayed that. We’ve got, since we’ve taken over the rig, we have one well down. We have another well exactly on pace where we thought it should be. And that yields more than $2 million per well in value creation straight from the top on all of the remaining opportunities ahead, which obviously is a massive needle mover. Thank you.

Operator: Next question comes from Neal Dingmann with Truist. Neal, please go ahead.

Neal Dingmann: Thank you, guys. Again, Rick, just congrats on a stellar career, and I look forward to continuing to run the ship. And, guys, my first question really just a little bit was asked earlier. On the Bakken and, I guess, what you’re calling the Rockies now specifically, Clay, I’ve noticed, you know, appropriately, you’ve stepped up the CapEx a little bit. I think you’re saying around a billion with four rigs. And I’m just wondering, given your planned focus here on Grayson Mills and think the continued operation efficiencies, you know, do you anticipate potentially seeing more growth here later in the year, or is the plan just to kinda keep things stable? What ideally would you like to see here?

Clay Gaspar: Yeah. Good point on the Rockies versus the Williston and Powder. We’ve combined those. We think it simplifies the story. It really is interesting assets. So we’ve got the legacy Williston position. We have the Grayson Williston position. And then we have the legacy Powder position. And so, really, when we think about, you know, overall, Williston, excuse me, let’s start with Grayson. When you think about Grayson, it’s pretty gonna be pretty flat to where it’s at now. We’re gonna run three rigs there. We see efficiencies we were talking about, not just in the capital cost, but the timing associated with that. That certainly helps productivity. Yield really nice capital efficiency. When we flip down to the Powder and we started looking at that asset, you know, that was an interesting one.

I think that one’s, again, having more support of not needing that asset today allows that team to do a little bit more of the science work to really unlock that potential, and I think it has a tremendous part of our value as we think forward and where it fits in the portfolio in coming years.

Neal Dingmann: No. Well, that’s love to hear it then. Forward to seeing what you’re gonna do there. And then secondly, just on the Delaware operation specifically, you all continued. I think it’s demonstrated how efficient the program continues to be there. I’m just wondering, what’s noticeable is, you know, versus some maybe some others, is that your midstream infrastructure situation appears to continue to be very strong with no takeaway issues. And I’m just wondering, is this performance largely due to contract? Is it, you know, you I know you’ve got some good search shakers that you’ve taken care of in the past. I mean, what is, you know, again, been able to efficiently drive this premier takeaway.

Jeff Ritenour: Hey, Neal. This is Jeff. Yeah. You’re exactly right. We’ve done a lot of work over the last couple of years. Our marketing team and the business unit collectively, they’re working with our third-party providers on making sure that, you know, we’ve got the gathering, we’ve got the processing capacity that we need, and then ultimately, the takeaway as it relates to both the gas, NGLs, and oil. So that’s been a really big team effort, you know, over the last couple of years. You go back two or three years ago, there were certainly some more challenges in the basin. Today, we feel really good about the position that we’re in. Really don’t see any roadblocks on that front. So feel really good about our ability to move the gas.

I should mention this as well. Water is not a light issue that the team is, you know, combined, they’ve done a really great job to make sure that we’ve got the takeaway that we need for all those products and excited about, you know, the pricing improvement that we’ve seen, you know, just over the last six months in that basin.

Neal Dingmann: Again, congrats, guys. Great quarter.

Operator: The next question comes from Neil Mehta with Goldman Sachs. Please go ahead.

Neil Mehta: Yeah. Good morning, team, and, Rick, congrats on an amazing 45-year career. And, Clay, congratulations to you. And Clay, maybe that’s a good place to kick off. A couple of times in the prepared remarks, you talked about the organic opportunity set. Are we reading into your early strategies as you step into the CEO role to really pursue more of an organic versus an M&A focused strategy and that the optimal thing to be buying back here is your own stock versus incremental assets?

Clay Gaspar: Yeah, Neil. Thanks for the comments again. And I think you’re reading that right. I just see real tremendous value creation kinda underfoot the portfolio we have today. And that can come in many different forms. I mean, small land trades that’ll never make the earnings presentations to more material things like we just announced with BPX. Those are real massive value creation opportunities that are typically no cash out the door. In addition to that, we think about the technology application, you know, flattening the base decline on our business is a massive opportunity. And I can tell you that the teams that are working on things like artificial lift and really applying kind of real-time diagnostics to those opportunities is, again, hard to put and describe on a slide.

But have the biggest value creation opportunities as we think about them, you know, the coming decade and beyond for the organization. So really excited about that. Objectively, look, we’re always gonna stay close. We believe in consolidation. If there’s a right opportunity for us, we’ll remain open to that. But I think our primary focus is just making Devon Energy Corporation a heck of a lot better Devon Energy Corporation.

Neil Mehta: Yeah. It’s very clear. And then Clay, just a follow-up on slide four in DeWitt, particularly in Eagle Ford. Can you just talk about why you think ultimately the partnership dissolution makes sense, how we should think about the uplift in value, and where does it ultimately come from? Is it from volumes? Is it from capital efficiency? And is it about how you ultimately prosecute this acreage?

Clay Gaspar: I would have to say first on the list as we run the waterfall and think about the value creation, there’s no doubt about it. Saving $2 million plus per well off the top is roughly about $2 million in NPV per every single well out there. So that’s a real opportunity for us and certainly is the headline approach for us. But controlling the pace is really valuable as we think about how quick these wells, we drill these wells in seven days. And so being able to control that when we need to, being able to back off when we have the opportunity to, you know, I know refracs aren’t the hottest topic du jour, but I can tell you there is real material value, and as we see more and more value creation from this, what we call is magic rock, it continues to yield more and more opportunities, and that’s what we’re really excited about.

But again, I’ll reiterate, I think this is a mutual win-win. Sometimes you bring together these joint ventures and you see the opportunities there, are the same token. Opportunities can change, evaluations can change, technology can change, motivations can change. It can be time to disillusion. I mean, a similar analogy is, you know, selling midstream assets and buying midstream assets back in, you know, both can be right at the given time. I would say when I think about the BPX opportunity, this is the right move for them now, this is the right move for us now.

Neil Mehta: Correct.

Operator: Thank you. The next question comes from Arun Jayaram with JPMorgan. Please go ahead.

Arun Jayaram: Good morning, gentlemen. I was wondering if you could maybe highlight the strong sequential performance in the Eagle Ford. I think your volumes were up over 20% sequentially. The well count didn’t seem like that was the driver. So maybe just help us understand, you know, kinda what drove that and thoughts on kinda sustaining that above 90 MBOE per day kinda figures as we think about, you know, 2025 because it was the key driver, I think, of the beat as you highlighted.

Clay Gaspar: Yeah, Arun. Thanks for the question. You know, I want to commend the team on the incredibly value-creating work around D&C efficiency. You know, that’s where some of this starts and the compounding effect of just shaving off time on the drilling side on the completion side. We highlighted that in 2024, certainly seen some of those benefits there. I think as we move into the driver’s seat on those operational efficiencies, I think it’ll take a different pace and really add a whole different level of opportunity. Also from the production side, again, these wells, we continue to see incremental value creation even as we space these wells in what looks like fully developed DSUs can subsequently bring additional wells in, stimulate these, and this rock continues to produce and continue to give back to us.

One thing I want to caution you on is we did bring on a significant amount of wells in the fourth quarter early in the quarter, and so there’s a little bit of tailwind on that that’s probably not fully we’re able to replicate every quarter going forward. So I would caution you a little bit on extrapolating the fourth quarter runway, run rate. But certainly the operational momentum, the savvy, the hard work that the team’s doing feel like we’re about to grab another gear on, so hang on.

Arun Jayaram: Great. Great. Maybe a follow-up for Jeff. Jeff, if we do the math around call it $250 million of buybacks per quarter, maybe up to $300 million, you know, based on your $3 billion, you know, free cash flow number that you put in the deck, that would imply returning somewhere between 53% to 60% of your free cash flow. Understanding that, you know, you’ll use buybacks, you know, maybe to be, you know, opportunistically. But is it the intention to maybe return a little bit or to focus a little bit on the balance sheet versus cash return in 2025? Just going through the math around that.

Jeff Ritenour: Yeah. I appreciate the question, Arun. You know, actually, it’s one of the things we’re talking a lot about with the internal focus that Clay’s described this morning. You know, really, that’s all a function of us driving our breakevens lower. And so what we’re really about is, obviously, that makes it that much easier for us to sustain and grow our fixed dividend. And it also allows us to reevaluate that share repurchase, you know, range that we’ve laid out, the $200 million to $300 million. So as we work our way through the year, as Clay just mentioned, we catch another gear and we start to see these efficiencies continue to build into our numbers, I think that we’ll like. Now that being said, we do have a $2.5 billion debt reduction target that we’ve laid out there, you know, last year.

We’ve already hit $500 million of that last quarter with the maturities that came due in 2024. We’ll have another $500 million this year of maturities, and then we’ve got our $1 billion term loan coming due next year, and so we’ll have ample opportunities to pay down debt, and we agree with you with the cash flow, the free cash flow projection that we’re looking at today. The efficiencies that we’re seeing worked their way into the numbers. I think there’s upside on our ability on the cash returns to shareholders, specifically on the share repurchases.

Rick Muncrief: Arun, I wanted to wish you the best as you approach retirement. I’ve enjoyed all the war stories with you over the years, and hearing about how the industry has evolved, and Clay, it’s also great to see you in the CEO seat. Remember our time together as we used to follow Anadarko. But best wishes to both of you.

Arun Jayaram: Arun, thank you very much for your kind comments. Both of us. And best wishes to you in the future as well, buddy.

Operator: The next question comes from Paul Cheng with Scotiabank. Please go ahead.

Paul Cheng: Hi. Good morning. Morning. Can I just understand that when you did dissolve the JV with BP, you’re saying that you’re going to save the cost by about $2 million per well. And from a design standpoint, I mean, as a JV, you are the partner? And is that in the maybe bottleneck or hurdle that to disallow you to achieve those savings? So all along, I’m trying to understand that. I mean, explain that how that why just dissolving it all of a sudden that we would be able to see the $2 million saving. The second question is on the Delaware. I think last year that you did about 230 wells. And then before that, like, 200, a little bit less than 240 wells. So you’re now doing 250 to 270. What we think that as a result, your production for 2025 maybe is going to be higher than what we suggest in the guidance.

I mean, can you tell us that the cadence on the well coming on stream? Is it the we need more towards the end of the year? That’s why we’re not seeing the full benefit this year or that because it’s the multi-zone and then you’re looking at a lot of the secondary branches. So as a result, that the production on those wells may be somewhat lower even though the return is good. Thank you.

Clay Gaspar: Thanks, Paul. Let me start with the first question, the BPX D&C JV. So this JV was pretty unique. BPX handled the drilling and the completions, and then Devon Energy Corporation handled the facility’s design and the production. So there was a pretty good split. Now we certainly tried to work with each other. We had different views on how to approach spacing design, well design, rack design, lots of different things, and, you know, sometimes we’re able to come together and sometimes we weren’t. The advantage that we have and the reason I’m so confident in these numbers is after the Valerus deal, that gave us the real opportunity to do our own D&C, run our own rigs, and really compare side by side. And sometimes, we’re seeing opportunities next door, side by side, DSUs. And so we’ve been able to extrapolate that, understand what it means to us, and this was a significant motivation for us.

As I said, we’ve already got our hands on the wheel. We’re seeing that improvement come through, and we feel very, very confident in being able to achieve what I said was greater than $2 million. In addition to that, the amount of control that we’ll have, our ability to dial up, dial down activity as we need to, I think is a huge value creator as well. So really excited about that. And again, we’re really, really pleased. This has been a long conversation that we’ve had, and finally, the stars have aligned where both sides could feel really good about doing this. Your second question was to the Delaware, and I think the heart of the question is really seems like productivity on a per gross well basis is down. What I want to caution you is there’s a little bit of a difference in working interest.

So last year, on average, 2024, we’re about 80% working interest on average, 2025 about 73%. Don’t see this as a trend. Don’t extrapolate those numbers. That’s just the way that the wells kind of fell to us. We’ve got a smattering of different working interests in the area. And it actually kind of alternates eighties and seventies, even down to sixties in one or high sixties in one quarter. But that’s just the way these big pads come in, and they can really influence the overall average for that quarter. So anyway, just want to make sure you’re aware that it’s not a productivity issue. As we think about the incredible productivity we displayed in 2024, we think 2025 is gonna be like for like, Wolfcamp A’s, Wolfcamp A’s, Cotton Draw to Cotton Draw, equally productive.

Now we did caution in the prepared remarks that we have a slightly different well mix. We’re digging in deeper into some of the Wolfcamp B zones. We truly believe is the right value creation strategy for the organization and for the shareholders, which does provide a different mix. Sometimes that’s in working interest. Sometimes that’s in GOR. But all of that’s baked into our guidance. So thank you very much for the question, Paul.

Paul Cheng: Thank you.

Operator: The next question comes from Doug Leggett with Wolfe Research. Please go ahead. Your line is now open. Please proceed with your question.

Clay Gaspar: That’s the easiest question I’ve ever had from Doug Leggett. So we can move on to the next.

Operator: The next question comes from Roger Read with Wells Fargo. Moving on, our next question comes from Roger Read. Please go ahead.

Roger Read: Oh, well, Doug’s loss is my gain. Good morning, everybody. Or maybe tomorrow. Anyway, quick congrats to you, Rick. And, Clay, we look forward to working with you going forward. So these transitions are always beat, but be entertaining nonetheless. I just really wanted to follow-up on kinda one key question, Eagle Ford. You mentioned the refracs, you know, maybe not the most interesting or exciting, but we’re hearing more and more about it. Where do you think you are in terms of working on some of the refracs and how you think about that from a returns that are an impact basis relative to, you know, just a baseline operations?

Clay Gaspar: Yeah, Roger, let me be clear. We are very pro-refrac. I think the market just doesn’t have a whole lot of excitement around it. So that’s fine. We don’t need to talk about it a whole lot, but know that we’ve got a huge inventory of opportunities ahead. And we have done a tremendous amount of work in that space, more than 40 in the Eagle Ford, more than 40 in Williston, and really have a good understanding of what works, what’s the right recipe, and how it fits in. The interesting thing with this dissolution of our joint venture is those refracs actually move down in our priority list because the well productivity and the well value creation has moved significantly up. So you’ll probably see a little bit slower cadence of refracs, but know that we’re just as confident as we were.

We see tremendous value creation from those and remaining upside. Again, this kind of falls into that organic value creation. You know, extracting more from the resources that we already have underfoot is the name of the game. And the beauty of those refracs, just to tout that just a little bit, is the full cycle cost and economics of those refracs is exactly the half cycle cost. Because the primary well is already underwritten the entry cost of that land. So when you’re really thinking about it on a full cycle like-for-like basis, these refracs are tremendously valuable. And I think there’s more to come on, you know, thinking about how we do artificial lift strategy, how do we apply technology to continue to think about that, flatten those base declines, improve those recovery factors, you know, we’re still an overall, you know, 10% plus or minus recovery factor on these resource plays, feathers tremendous value creation from the incredible position that we have.

No accident we’re in these five particular basins, very prolific, lots of zones, uphole and downhole from where we sit. And by the way, lots of oil remaining in those zones that we’re already producing from. So really excited about that, and you’ll hear more about that in coming quarters.

Roger Read: Appreciate that. Just a quick follow-up. Trump tariffs impacts on some of the materials that are used in wells. How is that reflected in your CapEx guidance? Or, you know, is there a plus-minus we should be paying attention to there?

Jeff Ritenour: Yeah, Roger. That obviously has been flying around on tariffs, and your guess is as good as mine as to when those will land and what will be the go-forward game plan. But we have done some work with our supply chain team to try to understand, you know, what that could look like, what the impact would be. You know, frankly, as we’ve done the rough math, which I would describe as pretty aggressive, kind of assuming that the tariffs were in place today, all the tariffs that have been talked about are in place today and carried forward into the future. We view it as less than a 2% impact on our overall capital program for the year. So really don’t see it as a big impact at this point in time, and now that being said, we’ll watch with everybody else the news and see what ultimately gets decided. But feel pretty good that it’s gonna have a minor impact on us at this point.

Roger Read: Yeah. Well, given the uncertainty, you can understand why I asked you the question instead of coming up with an answer on my own. Thanks, guys.

Jeff Ritenour: Yeah. We appreciate that. Thanks.

Operator: Next question comes from Kevin McCurdy with Pickering Energy Partners. Kevin, please go ahead.

Kevin McCurdy: Hey. First, I wanted to say to Rick that we’ll miss you on these calls. And, you know, I personally appreciate all the answers you’ve given me over the years at Devon Energy Corporation and WPX before that.

Rick Muncrief: Thanks, Kevin.

Kevin McCurdy: Only one question for me. I wanted to ask what changed on your 2025 capital plan over the last several months that you were able to lower your guidance? Was it mostly just a reduction in Permian and Eagle Ford well costs or, you know, any specifics that you can give us on basin details would help.

Clay Gaspar: Yeah. Thanks for that question, Kevin. I mean, there’s a lot of things at work. We’re always pushing the teams. We’re encouraging. We’re making sure that we capture those realized gains. You know, as we provide a soft guide in November and then continue to hone that, you know, there’s a few things that we felt very confident in at this point that we weren’t as confident in capturing back in November. And, you know, top of that list is certainly the gains in the Williston. You know, the $600,000 per well is a material improvement that we didn’t have fully grasped at the time of the last call. And then second is this BPX dissolution. You know, certainly, that is a huge needle mover for us. Now across the board, as I mentioned in the prepared remarks, the operational efficiencies that we gained in 2024, we expect continued tailwind momentum on that.

But we have not baked in any additional deflation or contract terms that we don’t already have in place today. Basically, from an inflationary, deflationary standpoint, we assume a little bit of, essentially, status quo, and we are pretty at least betting on the margin, we have equal chance of going up or down at this point. Feel really good about where we stand for our 2025 guide.

Kevin McCurdy: Thank you for the answer. And sorry if I cut you off earlier, Rick.

Rick Muncrief: No, Kevin. My only point was I’ve enjoyed working with you and a lot of your peers and colleagues here. It’s just been a pleasure. And the change in our industry is just phenomenal. It really is. And people are so best in the world, and I’m really proud of what we have done these last four years post-merger here at Devon Energy Corporation. We have built a just a forklift of a company, and so proud of the people here and the assets we have.

Kevin McCurdy: Take care.

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

John Freeman: Good morning. And, yeah, just echoing prior congratulations both to you, Rick, and Clay. All the best. The first topic for me, just, obviously, we’ve seen a dramatic improvement in natural gas prices. Jeff, you did a good job showing on slide eight kinda y’all’s improved, you know, all the options you’ve got on the marketing side, dramatically better realizations on the gas side, and I can appreciate the fact that months go into coming up with, like, a 2025 plan. But I’m just curious, having, like, a diversified asset base like y’all do, if, you know, there’s any potential flexibility in the program, if, you know, gas prices remain strong, maybe improve further from here, if there’d be any potential kind of shift in the plan to certain assets that potentially benefit more from the really robust gas price strip we’re looking at right now.

Jeff Ritenour: Hey, John. This is Jeff. Yeah. Thanks for those comments. And, you know, it’s absolutely something that we’ll monitor and be mindful of, but frankly, as we’ve done the analysis for a number of years, when we look across each of our different basins, they’re all focused on that oil production and the high, you know, outcome that we get from producing the oil. So most of the gas upside, as we highlighted on the slide, we think will come from our associated gas. But there’s a significant amount of additional resource, you know, underfoot in each of those basins that we could go prosecute in the future as we see continued momentum around pricing. So we feel really good about the position we have. We think it’s one of the benefits of the multi-basin portfolio.

It just gives you a lot of shots on goal and opportunities that a lot of other companies frankly just don’t have. And again, I just want to thank the marketing team for doing such a great job of, you know, getting those molecules to market where we see the highest demand and the best opportunity to get the highest realized price.

John Freeman: Thanks. And then just one quick one for me. The 2025 plan, the 22 rigs, how many frac crews does that assume? I was just looking relative to six y’all ran in 4Q.

Clay Gaspar: Three consistent crews in the Delaware. We may top that with a spot crew here and there. And then about two to three other frac crews depending on how you count them during the time. But yeah. So I call it ballpark six.

John Freeman: Got it. Thanks, Corey. Appreciate it.

Clay Gaspar: You bet, John.

Operator: The next question is from Doug Leggett with Wolfe Research. Doug, your line is now open. Please go ahead.

Doug Leggett: Hey, guys. Apologize for the problems earlier, but I wanted to make sure I’m traveling currently. Wanted to make sure I got a chance to come on and wish Rick well. Rick has been a pleasure, and amazing to watch what all the changes have taken place. I wish you well. And, Clay, look forward to seeing you in the seat. But I do have a question for Clay and for Jeff, if I may. And as, predictable as always, one of them is to do with the balance sheet. So let me start there, Jeff, if that’s okay. When we talk about inventory depths with Devon Energy Corporation, you know, we’ve talked about, you know, ten years at sixty and maybe higher that eighty and so on, you guys have given us out before. And if I think about, well, that basically means if you’ve got a less than three percent dividend, you need, you know, thirty-three years to get your money back, and you’re telling us you’ve got ten to twenty years of inventory.

So I guess my question is, how do you stack the importance of the dividend, the buyback, and the balance sheet when you think about free cash flow, because you still have twenty-five percent of your capital structure is debt. And ultimately that amplifies your equity volatility, you know, depending on what comes with the commodity. So I guess my question is why not target balance sheet before you allocate two billion dollars to the buyback. That’s my first question. My second question, if I may, is to follow-up on John’s, actually. And, Clay, I don’t know if you wanna get into this in any detail, but I mean, gas markets are obviously changing in the US. It’s, you know, it’s been a year. We’ve held for some time, and you have a lot of optionality to be more than, you know, than talk about, you know, second-order derivative gas exposure, you could actually go direct.

And for example, rather than just expand the DAO, back to more direct spending in some of your gas plays. I’m just curious what it would take for you to do that for those to be competitive versus your latest targets. And I’ll leave it there. But thanks again, and congrats, Rick.

Jeff Ritenour: Yeah. Thanks, Doug. I appreciate the question as always. And I’m probably gonna sound like a broken record here because we talk about this every quarter with you, but, you know, for us, it continues to be all of the above. We think that the fixed dividend, the share repurchase program, which obviously drive our cash returns to shareholders, is absolutely table stakes. And the balance sheet, well, you know, without question is a priority for us. You see from the framework that we lay out, you know, the first thirty percent of our free cash flow goes right back to the balance sheet. So I think that underscores, you know, our priority for, you know, maintaining that strong investment-grade, you know, position that we have today.

And you’ve seen us execute on that for a number of quarters now. On top of that though, again, you know, what we’ve seen in the market, what we continue to hear from our shareholders, is that the cash returns are important. Folks like the growing fixed dividend, and then we supplement that with the share repurchase program. So when you put it all together, we feel really good about the value proposition that we’re delivering and plan to execute on that, you know, well into the future. I’ll flip it over to Clay.

Clay Gaspar: Yeah. Thanks for the question, Doug. That sounds like the Doug we know. I was thinking we might be getting a pass on an easy, non-hard question from you.

Doug Leggett: Yeah. So let me start with you. You mentioned we got a big company. I perform on, you know, Claire. We got to ask the hard ones.

Clay Gaspar: Hey, man. I’m all for it. I’ll take that every day. Yeah. You bet. So let me go back to the ten years of de-risked inventory that we’ve talked about. You’ve acknowledged Inveris, and others acknowledge third party. Please don’t mistake that as we’re in a blowdown mode, and, you know, the fifty-three-year-old company is gonna live to be sixty-three and then we shut the whole thing down. There’s no intention of that. We certainly plan to rejuvenate the inventory, continue to do some hard work to continue to be creative and extend the runway, you know, for decades out into the future. Now that’s hard work to do. I’ve talked about some of the organic things that we have, you know, in hand today that we really think provides incredible value, but this company has been built on hard work and hard decisions, as I mentioned, for fifty-three years.

So second, let me shift to your second question on that. And you talked about the gas inventory. As Jeff mentioned, we do have a very substantial amount of gas inventory specifically in the Anadarko Basin and in the Delaware Basin. We love to test our portfolio. We’ve got a really cool black box model that you can put in whatever kind of scenario you want. And it tells you ideally this is how you should prosecute the opportunities that you have. And so we love to test that. We tested, I think, every oil and gas price combination you can think of, and what it keeps telling us is that even in the foreseeable future, the gas prices we’re seeing today and even in the upside cases that we’ve run, it continues to point to our robust returns related to our oil processes, our oil opportunities.

And so that is where our dollars are really being directed, but please know that we continue to keep our eyes wide open to those opportunities. And absolutely, there’ll come a time when the call for gas is strong enough relative to oil, and we’ll be ready because we’ve got some really good inventory in our portfolio today.

Doug Leggett: It’s very clear, guys. We’ve you in a couple of weeks, Clay. Thanks so much for that.

Clay Gaspar: Sounds great, Doug.

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

Matthew Portillo: Good morning all, and I as well wanted to pass along congratulations to Rick and Clay in the new role. Maybe just a follow-up there, Clay, on the Anadarko. Been a while since we refreshed our thoughts on inventory depth in the basin. Just curious if you might be able to give us some context around how you think about inventory, especially in the context of higher natural gas and NGL prices, as you mentioned, progressing that program through the course of 2025 and beyond.

Clay Gaspar: Yeah. Thanks for the question, Matt. You know, we have needed the partnership in DAO to really promote the economics of the opportunities that we’ve had so that they can viably compete in the portfolio relative to the other opportunities. And we think even in today’s commodity price, that that’s the right move going forward, displayed by our extension of the JV that we have with Dow. Now the team continues to look creatively, as I mentioned, up and down the whole thinking about the rest of the basin, the opportunities there, expand our footprint, very methodically, that we’ve done very well on that. And there will be a time when those opportunities really are on the more of the forefront. For now, we’ll quietly keep working in the Anadarko Basin.

We’ll leverage resources like this financial arrangement so that we can make sure that we’re being very prudent with the investor dollars and making sure that we are delivering the returns that we are expected to deliver in the organization that we have and competitively with the high-quality portfolio that we have in the other basins.

Matthew Portillo: Perfect. And then maybe just a follow-up question on the Permian. You mentioned obviously chasing the Wolfcamp B in a bigger program for 2025. I was curious if you could maybe provide some context around how much that program made up in 2024, how you’re thinking about it in 2025, and then I guess for the Permian as a whole, how should we be thinking about the oil cut? I think you’ve been averaging around, you know, forty-six, forty-seven percent through the course of the end of last year. Should that mix shift change dramatically, or should we expect that to be pretty constant going forward?

Clay Gaspar: Yeah, Matt. Great question. Love talking to the Delaware Basin. That’s our crown jewel asset, and, you know, the team there is doing some very incredible work creating value. You know, Jeff mentioned earlier some of the work that the marketing team did in ensuring that we had takeaway capacity, you know, that’s over the course of years that that kind of investment and relationships that we have to lean on to make sure that that happens. Last year, we talked about digging deeper into the Wolfcamp B, really testing how best to prosecute those opportunities. Should we develop them now? Should we stay later with them? And so I’ll let John Rains talk a little bit about, since he was leading the team at the time, talk a little bit more about what we learned in 2024 and how we’re applying that to 2025.

John Rains: Yeah, Matt. Thanks for the question. As Clay said earlier, we’re diving in more to these multi-zone developments, and through appraisal, we’ve gotten a lot more comfortable with the Wolfcamp B, and so we continue to lean in. We feel like this is the right development philosophy for us in the Delaware Basin. So when you think Wolfcamp B from 2024 and 2025, I think your question was around allocation. And so we’re moving from about ten percent of our total program in 2024 up to about thirty percent in 2025 that will co-develop with Wolfcamp A. And I think your second question, if I heard you correctly, was around oil mix. Oil mix is gonna be pretty consistent. The Delaware Basin year over year, I think, for somewhere around forty-seven percent last year and maybe slightly below that, but really consistent year over year.

Matthew Portillo: Thanks, all.

Operator: The next question comes from John Davenport with Johnson Rice. Please go ahead. John, your line is now open. Please proceed with your question.

John Davenport: Another one of those hard wagamoy kinda side.

Clay Gaspar: Hello?

John Davenport: Oh, there we go. My question’s been answered, but thank you, guys.

Operator: Alright. Thank you, John. The next question comes from Paul Cheng with Scotia. Please go ahead.

Paul Cheng: Hey, guys. Just a real quick follow-up. Okay. For the CapEx spending, do you have a cadence and also the number of wells coming on stream? Do you have a cadence that how it’s going to look for the year? Thank you.

Clay Gaspar: Paul, tell me again which basin were you talking about there? The Cadence?

Paul Cheng: In that actually, on all of them, in general, that I mean, I think that you guys do you expect that it’s going to be period prorated throughout the year? Because your production outlook seems like that’s what you suggest. But in terms of actual spending and also the number of wells that you’re going to come on stream, is there anything that we should be aware that is not really prorated?

Jeff Ritenour: No, Paul. I would say as a general statement, the, you know, the IDs as they work their way through the year, and this is on a gross basis, are generally pretty consistent. You know, the capital actually were we think it could trend down as we work our way through the year. First quarter is likely gonna be the highest CapEx quarter for us. And you’ll see that trend down over time.

Paul Cheng: Okay. We do. Thank you.

Rosy Zuklic: So we have reached the conclusion of our call. So thank you, everyone, for your interest in Devon Energy Corporation. And if you have any further questions, please reach out to Chris or myself.

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