$DVN Devon Energy Q3 2024 Earnings Conference Call

Welcome to Devon Energy's third 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 Mrs. Rosie Zulick, Vice President of Investor Relations. You may begin.

Good morning, and thank you for joining us on the call today. Last night, we issued Devon's third quarter earnings release and presentation materials. Throughout the call today, we will make references to these materials to support prepared remarks. The release and slides can be found in the investor section of the Devon website. Starting this quarter, we are providing slides specific to the earnings call discussion. In a week or two, we will publish a more comprehensive deck that will include slides that were previously provided. Joining me on the call today are Rick Muncrief, President and Chief Executive Officer; Clay Gaspar, Chief Operating Officer; Jeff Rittenour, Chief Financial Officer; as well as other members of management. 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 materials. With that, I'll turn the call over to Rick.

Thank you, Rick, and good morning, everyone. Turn to Slide 4. Devon's third quarter performance reflects exceptional operational execution across the board. The third quarter performance is a continuation of outstanding quarterly results and a product of our focused approach to operational excellence. The organization continued to build on the momentum that we've captured in the first half of the year, positioning us to round out 2024 with very strong momentum. These results tie back to three key factors: our premier asset portfolio, a talented and value-focused organization, and third, a disciplined capital program designed to optimize returns through the cycle. Each of these elements combined to contribute excellent well productivity, improved cycle times, and better base production results across our diversified portfolio. I'm confident we will continue to build on these accomplishments into 2025 and beyond. Moving to Slide 5, the Delaware Basin was the primary contributor this quarter to our earnings, with approximately 60% of the capital allocated to this basin. This investment led to record basin-level production volumes of 488,000 BOE per day, representing a 6% growth rate compared to the previous quarter. The volume growth was fueled by 55 new wells primarily targeting the Wolf Camp formation, with a subset of Bone Spring and Avalon wells included in the mix. Collectively, these projects exceeded expectations, achieving average 30-day rates of more than 3,100 BOE per day per well. On the map to the left, we have highlighted one of the primary contributors from this quarter, the CVR 121 development. This project co-developed the Wolf Camp A, Wolf Camp B, and shallower zones in the Bone Spring. In total, the Stateline area development targeted six different landing zones. We brought these wells online during the second and third quarters, successfully managing any localized facility constraints. The 30-day rates from this 21-well package averaged 3,300 BOE per day per well, and estimated recoveries exceed 2 million BOE per well. The CVR 121 has provided additional insights that have helped us further advance our resource development strategy as we continue to balance the triple mandate of returns, NPV, and inventory. The 121 gives us additional confidence in this winning strategy. Our team continues to de-risk multiple secondary targets across our core development areas in the Delaware Basin. The great work that the team is doing in balancing the near-term performance with the long-term inventory considerations confirms our confidence in a multi-year runway of outstanding performance from the Delaware Basin. Turning to Slide 6, we've seen our Delaware Basin well productivity outpace the previous year by an impressive 20%. This is evidenced by the robust production growth and superior well results achieved to date. As shown on the right-hand side of the slide, we also continue to realize meaningful operational efficiencies. Notably, the broader adoption of Simul-Frac across the Delaware Basin activity has been a key driver, enhancing completion efficiencies by 12% year-to-date and consequently increasing our days online. From a drilling perspective, our teams are continually finding ways to optimize our rig fleet and improve operations to enhance capital efficiency. These efforts have yielded tangible results, evidenced by a reduction in drilling days and a 14% improvement in drilling efficiencies in 2024 compared to the previous year. Efficiency gains have allowed us to reduce drilling activity from 16 rigs to 15 rigs this quarter. We plan to drop an additional rig in the first quarter as a result of these efficiencies. At the current pace, we expect to duplicate 2024's 16-rig output with 14 rigs in 2025. This impressive efficiency performance is a result of a focus on operational output without taking our eye off the imperative of doing things the right way. Alongside these incredible efficiency improvements, our safety and environmental metrics have also moved in a very positive direction year-over-year. Let's now shift to the Williston Basin on Slide 7. We closed on the Grayson Mill transaction in late September. I'm pleased to report that the integration is progressing quite well, and I would add that it is our best integration to date. The teams on both sides have jumped in and are excited about the opportunity to learn, challenge, and improve existing processes. We're currently operating three rigs in the Williston Basin and plan to roughly maintain this level of activity going forward. In the fourth quarter, production from the acquired assets is expected to slightly exceed our initial expectations, and we plan on investing approximately $150 million of capital in the new assets. For 2025, we aim to sustain the acquired assets at approximately 100,000 BOE per day. Our capital plan will feature two- and three-mile laterals and tactical refracs to supplement the base production. Enhanced scale in the basin will drive additional capital efficiencies, operational improvements, and marketing synergies. The acquisition also adds 500 undrilled locations, further enhancing Devon's free cash flow profile for many years to come. I'll now hand it over to Jeff to go over the financials for the quarter.

Thanks, Clay. Starting on Slide 8, highlighting our third quarter financial performance. Devon's core earnings totaled $683 million, or $1.10 per share. EBITDA was $1.9 billion, and we generated operating cash flow of $1.7 billion, each exceeding consensus estimates. After funding our capital requirements, we generated $786 million in free cash flow for the quarter, a significant improvement over the previous period. Our cash flow generation was underpinned by oil and total production that exceeded the top end of our guidance, due to the excellent operating performance highlighted by Clay earlier. Production costs improved 7% from the prior period, driven by less downtime resulting in lower workover expense, and finally a lower cash tax rate, primarily a result of accelerated tax depreciation due to the Grayson Mill acquisition. Our solid financial performance enabled another quarter of strong cash returns for shareholders. During the quarter, we distributed $431 million to shareholders through fixed dividends and buybacks. We spent $295 million on share repurchases, bringing our program total spend to just over $3 billion. We elected not to pay a variable dividend this quarter. The variable dividend will remain a tool within our cash return framework, but in the near term, we expect to deliver cash returns to shareholders through our fixed dividends and share repurchase program. Foregoing the variable enabled us to reduce net leverage in pursuit of our $2.5 billion debt reduction target. We expect to utilize cash on hand and a portion of free cash flow generated each quarter to pay down the $1 billion term loan we put in place for the Grayson Mill acquisition. As highlighted on Slide 9, we exited the quarter with a net debt to EBITDAX ratio of just over one times and strong liquidity between our cash balance and undrawn credit facility. We've already retired $472 million of outstanding senior notes this year and have additional opportunities to further reduce our leverage with upcoming maturities, the paydown of our term loan, and outstanding callable debt. Moving to Slide 10 and looking ahead to 2025, we expect another year of strong performance, with total production forecasted to average around 800,000 BOE per day. This production outlook is nearly 5% higher than what we communicated just a few months ago when we announced the Grayson Mill acquisition. Also, with the benefit of Grayson Mill and the operational momentum we established in 2024, we expect record oil volumes in 2025 averaging around 380,000 barrels per day. On the capital front, we anticipate spending to be between $4 billion and $4.2 billion for the year. Importantly, with this disciplined plan, we are well positioned to generate robust free cash flow at today's prices and offer a free cash flow yield that exceeds the broader market. Moving forward, with the allocation of our free cash flow, we believe our financial framework provides us the necessary flexibility to deliver market-leading cash returns for our shareholders and achieve our debt reduction goals. We will continue targeting up to 70% of our free cash flow as a cash payout for shareholders and make progress on our $2.5 billion debt reduction program. We expect share repurchases in the range of $200 to $300 million each quarter and will retain free cash flow beyond our share repurchases on the balance sheet to reduce our net leverage. We'll provide complete 2025 guidance on our February call after we finalize our budget with our board. With that, I'll now turn the call back over to Rosie for Q&A.

Thank you, Jeff. We'll now open the call for questions. Please limit yourself to one question and a follow-up. Emily, we are ready to take our first question.

Thank you. Our first question today comes from Aaron Gierd with JP Morgan. Aaron, please go ahead.

Yeah, good morning. I was wondering if you could highlight some of the drivers of the uptick in well productivity in the Delaware Basin. I know you shifted some activity from Monument Drawback to Southeast New Mexico, and I'd love to get more details on that and what you're underwriting in terms of well productivity as we think about your 2025 plan.

Hey, Aaron, Clay here. Thanks for the question. First, let me reiterate the 2025 plan is still a soft guide. I'd like to note that this soft guide is a little better than the last soft guide, so we're continuing to improve our soft guide towards a February more constructive guide. But let me tell you a little bit about what we have baked in. There's an assumption on the cost side of the equation relative to where we're at, a point in time today. There's obviously a lot of macro in the air, so we haven't assumed presumptively additional deflation or other significant moves in the system. Back to your question on the productivity, we've also assumed on a risk basis the wells that we have in place. We probably haven't fully baked in some of the upside that we've seen in regards to some of the breakthroughs we've had around well placement combined with completion design combined with the sequencing, and I think that's where we really continue to outperform and really had some great breakthroughs as we feather in some of these other more secondary-type zones. You're building in a multi-zone development strategy, and sometimes those wells, while economic, can be dilutive to the overall picture. What we've seen is with the right techniques going in, we're continuing to see some really phenomenal results from these deeper and some shallower benches, as depicted in the CVR 121 as an example. So I would say there's a little more upside in where we're headed, but objectively, we've got a soft guide out there. We feel good about where we're at. We'll continue to hone that and then see how we can improve from there.

Great. My follow-up is, you guys are six or seven weeks into since the close of Grayson Mill. I was wondering, Clay, maybe for you or Rick, if you could identify any self-help opportunities where you think you could further improve kind of capital efficiency in the Bakken in particular.

Our next question comes from Neil Mehta with Goldman Sachs. Neil, please go ahead.

Yeah, good morning, Rick and team. The first question is as you think about your M&A strategy, I guess there are a couple different paths you can look for that transformational transaction, when some have come and gone, but the other opportunity is to look for a bunch of additional Grayson Mill-type opportunities, which are much more bolt-on in nature. And as you think about M&A, where you've definitely demonstrated an interest in being active, what do you think is the right path and how are you thinking about maximizing value via M&A?

Okay, that's helpful. And then the follow-up is just maximizing your natural gas realizations, particularly in the Permian. You've discussed the in-service of Matterhorn, so I'm curious on how you think that ultimately is going to flow through Waha pricing, which has recovered but not nearly to probably the fair value. And do you think there's risk that this gas oversupply is transferred over to the Gulf Coast? And then maybe as part of this discussion, you could also talk about Blackcomb and how that resolves potentially the next bottleneck in Permian gas.

Yeah, Neil, this is Jeff. As you know, we obviously have a commitment on Matterhorn and have an equity contribution there as well. We're excited that the pipe is up and going and flowing to VCF at this point. Specific to Devon, I think you're very familiar with our approach in moving the molecules away from Waha to the Gulf Coast. So now with Matterhorn online, we have about 90% of our molecules flowing away from Waha to the Gulf Coast. You highlight the potential for a backup there at Katy, that's certainly something that we've been mindful of. Our team's done a great job and got out in front of that. We've taken capacity away from Katy over into the Louisiana hub. So we feel like we've taken some really positive steps to protect ourselves from some of the dislocation in pricing that you've seen there. We feel good about pricing longer term. As you mentioned, we're still in a spot today with a lot of the maintenance that we've seen on some of the other pipes there in the Permian Basin, which has led to kind of a depressed Waha price, even with Matterhorn coming online. But initially, once the pipe came on, we did see some improvement, and once some of this maintenance settles out, we expect that to continue. And our realized pricing going into the fourth quarter and certainly into 2025, we expect to improve over time.

The next question comes from Kaye Amin with Bank of America Merrill Lynch. Please go ahead.

Good morning, guys. Thanks for getting me on. For my first question, I'm also going to take a shot at 2025. You kind of addressed the Permian piece of the puzzle that there's an upside scenario there, but in your conservative base case, do you kind of see the Delaware oil flat or up? And the other moving part of that 2025 guide is the Bakken, where you're taking over Grayson and you're basically landing that production at a lower but more optimal level. Just kind of wondering about the cadence of that Bakken drawdown in 2025.

Yeah, I appreciate, this is Clay again. I appreciate the attempt at another 2025 question, and I imagine it might not even be the last. What I would tell you is, look, let's just stick with our soft guide for now. We have a lot more detail coming out in February. Meanwhile, we don't want to front-run the board. In a couple of weeks, we've got a really important board meeting. We'll talk about these things. We've got a lot of options, very deep portfolio. The multi-basin gives us a lot of optionality, and the team continues to provide some really interesting, kind of competitive opportunities to compete for that capital. So rather than getting too granular at this point, we're just going to stick with the high level that we've provided so far.

Fair enough. For my follow-up, just kind of thinking about debt reduction, in September you met your first go at your $2.5 billion target. And taking out the $500 million in the next several years before 2028, you've got about $2 billion coming due. In the base case, do you take those out as they come due?

Yeah, Kaye, this is Jeff. That's exactly the game plan. We feel really good about the balance sheet that we have, a lot of strength and liquidity as I mentioned in the prepared remarks. We're not in a hurry to go out and pay down a bunch of debt in the near term, but we are going to build towards that. And as you mentioned, our game plan is just to take out the maturities as they come due. I mentioned the $475 million that we took out here this year already. We'll have another, call it $485 million in the fall of next year that we'll look to take down. And then as I mentioned previously, the term loan, which has a maturity in 2026, we've got a couple years to start chipping away at that over time as well. So over the next three years, as we've highlighted, we'd like to get kind of roughly $2.5 billion of absolute debt out. But we feel really good about the kind of financial flexibility that we have with our framework to deliver on that, as well as again, I'll just highlight, our intention to deliver really competitive cash returns to shareholders over that timeframe as well.

The next question comes from Scott Gruber with Citigroup. Please go ahead.

Yes, good morning. How should we think about your LOE and GP&T costs going forward post-closing? We got the Q4 guide. Was there an opportunity to squeeze OpEx lower, or should we use the Q4 guide as the baseline for 2025?

Yeah, I think the Q4 guide is a good starting point. Again, we'll continue to refine that, look for opportunities. You might have noticed the Q3 to Q4 change, that varies quite a bit with the workovers. We're always trying to get more efficient, less downtime. That's a lofty goal. Things tend to tick up a little bit during the winter months on some of this downtime, so we've got that baked in in the fourth quarter. So if you run that forward, I think it gets you certainly in the right ballpark.

Okay, I appreciate that. And then just thinking about your completion efficiencies, quite impressive. How should we think about what you guys think about in terms of driving the next leg? Where do you guys stand on e-frac deployment? You mentioned the Simul-Frac, but are you thinking about e-frac deployment? Where do you guys stand on that front, and latest thoughts on you potentially looking at something like Trial Track, just kind of what could drive the next leg of completion efficiency gains?

Yes, Scott, I would say all of those things are on the table. We continue to evaluate them very objectively. We stay in the market pretty continuously to understand what those opportunities are. As you're well aware, some of the e-fleets required some pretty long-term contracting early on. As we cycle through those as an industry, I think there's more opportunity for us to participate and to see things that are really contributing to the bottom line. So far, we're pretty objective about the fuel types, and many of the fleets that we run actually run a very high percentage of natural gas. And so think of an e-fleet as 100% natural gas, where some of our fleets are maybe 60 to 80% natural gas. And so we're getting a lot of that cost benefit from depressed natural gas prices, and at the same time, we're in the market that may be a little bit secondary, some of the premium e-fleets. So far, it's been our competitive advantage or advantageous for us to stay the direction we're in. But I guarantee you, we are wide open to creative ideas, continue to innovate. The efficiencies that our service company partners create right alongside with our team, it is pretty remarkable. And I'm getting tired of trying to out-guess them on is this the time that we plateau, so...

You're thinking about when to plateau, man? Your guess is as good as mine, but I'm going to bet on the over on the creativity and innovation that these folks have, and they continue to apply. So more to come on that, and I look forward to sharing with you. Yeah, don't bet against ingenuity. Appreciate the caller, thank you.

Our next question comes from Roger Reed with Wells Fargo. Please go ahead.

Yeah, thank you. Good morning. Kind of two questions. One to follow up on your comments earlier about not really building in any productivity or efficiency. Maybe just a way to look back over the last 12 months, last six months, what those productivity and efficiency trends have been. In other words, if things were to continue along that line, what's sort of the potential for improvement on well costs as you think about it?

Yeah Roger, I'll take it kind of two parts. First on the overall productivity, let's focus on the Delaware because that's such a large piece of our business. Year-to-year productivity, we've been in a relatively tight band, but it's affected by our geographic contribution inside of the Delaware, the zonal contribution, and going forward our ability to move more of these multizone developments. While we're doing things to better land the wells and tweaking completion design to eke out more recovery factor, there's also some technical tension on maybe we need to tighten a few more of these up and really lean into this inventory opportunity. We all know this is incredibly precious inventory that doesn't exist really anywhere else on the planet. So we want to balance near-term returns, the ultimate NPV of the project, and inventory considerations. Shifting to the bigger capital picture, productivity is part of the equation, speed is part of the equation, and deflation is part of the equation. The completion and drilling efficiencies make wells cheaper on a per-well basis, but it works against you because you're pulling more of next year's activity into this year. We've mitigated that by dropping rigs, lowering the headline activity number, still getting the same output. But as you see from our productivity and continued beat and raise throughout the year, those productivity gains combined from well productivity and more wells online are outrunning even our internal estimates. Deflation is out there in the background, and the question is whether it keeps our capital in line. Saw a really good result in Q3, really pleased with Q4. We'll continue to watch that, don't want to get too far ahead of ourselves in '25 with all the macro things going on. A lot going on as we think about '25, but really excited about what the team's doing controlling the controllables on drilling better wells in a more efficient manner.

I appreciate the details and the answer. I'll turn it back. Thanks, thank you.

Our next question comes from Neil Dingman with Truist. Please go ahead.

Morning, morning guys. Thanks for the time. My first question, likely for Rick or you Jeff, just on capital allocation. I'm just wondering very generally, any thoughts these days any differently about how you're thinking about the buybacks versus dividends going forward? And then secondly, on the recent buybacks, do those include any PE shares, and would you all consider stepping a larger way into buybacks if any of the PEs decide to sell?

Yeah Neil, this is Jeff. First priority for us on the cash returns is the fixed dividend. We're in a position today where obviously with our business model we're really comfortable with where the fixed dividend is, and frankly expect to grow it as we work our way into next year. Once we start working through our finalized budget with our board, I expect after we get past the first of the year you'll see us announce growth in the fixed dividend. So that's the first priority. Beyond that, we've been pretty clear for the last several quarters that our bias is towards the share repurchases. We think there's great value on our equity today from an intrinsic value standpoint and our view of the long term. So you're going to continue to see us lean in on the share repurchase program. If you go back and look at our track record, obviously we've paid a variable dividend in the past. That really was attuned to the market dynamics with what we would characterize as above midcycle pricing. We think it worked incredibly well for us. Now with the pullback in commodity prices, we think it makes more sense to eliminate the variable for the near term and really lean in even further on the share repurchases and the growth in our fixed. So that's going to be our game plan going forward. Obviously if we see the market dynamics change, we'll adjust our strategy, but that's what we really feel like is the beauty of our financial framework — it provides us all the flexibility we need to manage through the dynamic environment we're all living in.

Yeah, I like that game plan Jeff. And then just secondly, Rick or Clay, just a broader question on potential future JV plans. It seems like some of your peers have started talking about power and nuclear. I'm just wondering if you all have started any of these conversations for any potential JVs with these types of plants?

Yeah, absolutely Neil. We've had a lot of discussions. Not only our asset teams but our business development teams have had a litany of discussions. I can also tell you that what I've personally been involved with is talking to the utilities and power pools just to make sure that we have the right framework and structure, and more importantly the support to get some of this done. Because until we address some of those sorts of things, I think we're kind of waving our arms a little too much. But to answer your question, yes, we've been very, very engaged in discussions. Me too on that as well. I think there's us as a pretty creative bunch, and we've got some folks that are really thinking outside of the box on how do we connect some of these dots. We have tremendous resources specifically in the Delaware Basin, and it's obviously not lost on us the current cost of electricity, the scarcity of that electricity, and at the same time we have the source of that electricity that is getting terrible price realizations. Connecting those dots with our incredible footprint, I think is a real opportunity. And yes, we're absolutely engaged in some of those conversations today.

Great, thanks. Our next question comes from Paul Chang with Scotiabank. Please go ahead.

Thank you. Good morning guys. Just curious, as you are trying to do more development and looking at the other branches, have you seen a noticeable difference in the gas-oil ratio or the sour gas exposure and all that?

Hey, thanks for the question Paul. As we move generally down in section, generally speaking it gets gasier, so that's no great surprise. I would say we've actually seen some upside to the oil cut in some of what we call B200, B300 benches that have really proven a lot oilier. We've got a couple of tests we're doing first half of this year that we're pretty excited about, even deeper benches. We've done a whole lot of geologic mapping and science work, oil fingerprinting, really understanding where those opportunities are to drill deeper, include more of these deeper benches and still keep our oil cuts up. So I'd say positive to the upside there, pretty excited, but overall remember we are moving down dip, you're kind of fighting uphill on the gas cut. Specific to the H2S, the only place we see it is in the far eastern side of the Delaware Basin in material amounts, and we're very aware of that. We work around it. We've got third-party midstream partnerships that are very engaged in that pretty much throughout that stack of rocks. It's not something that typically surprises us. We're very aware of it, we take that into account, and we make sure we have the appropriate safety and midstream infrastructure in place as we dig into that area.

And the second question is on inventory backlog. You have a 10-year inventory life, and how about in the Permian? If we look at using a, call it, $50 WTI and $3 gas price, what is your inventory life and how many wells you need in the Permian per year in order to sustain the operation?

Yeah, good question on inventory. We love talking about it because I think it's an area that's a little bit misunderstood. And I'll invoke third parties like Enverus to back up these numbers. We feel very confident in a 10-year runway in all five of our basins. Some of these have much longer — as an example the Powder River Basin — but even in our core, the Delaware Basin, we certainly feel really good about that runway. Now, no doubt about it, Paul, you think about the front five years versus the back five years, we have much more confidence in that front five years. In fact, when you look at the overall productivity and capital efficiency for the organization, I feel very good about that front five years. That just gives us five years to continue to innovate and get more efficient on that back five, and that's why I feel so confident about the 10-year runway. And then even beyond that, Rick's signaling to me over here, there's a lot more beyond that, and he's a great champion for our innovation beyond as we think about deeper zones, uphole zones, adjacencies in a business sense and in a geologic sense. There's a lot more to go from there. Again, don't underestimate these teams. The human ingenuity, the scrappiness of these folks across the industry is just so exciting to be part of, and I'm so proud to see it. Thank you.

The next question comes from Doug Leggatt with Wolfe Research. Please go ahead.

Thank you. Good morning everyone. Guys, I think all of us have been obviously trying to figure out why the stock has had such a tough time over the last period of time. There's a couple of things you brought up this morning I wanted to try and hit. The first one is, Jeff, when we hear you talk about 70% cash free cash return, buybacks, and you're going to raise a dividend, but at the same time you've avoided the variable because of your concerns over the commodity, while your capital structure still got $8 billion of debt at a backwardated oil curve — why is the balance sheet not getting more attention than a buyback given the uncertainty that you've yourself laid out this morning on the oil price?

Yeah Doug, we absolutely have a focus on the balance sheet. As I think we've been pretty clear about our intentions around reducing the debt over time. We have the luxury of the strength of the balance sheet and the liquidity that we have and the business model that we pursue with the low break-evens that we don't have to rush out and act like something's wrong with the balance sheet and be aggressive in some sort of debt paydown. We're trying to balance that with the value that we see in the equity. So as I mentioned earlier, we feel like the flexibility of our framework allows us to do both, honestly. We feel like we could accomplish both objectives over time — grow the fixed dividend, buy back our shares at what we view as a discounted price, and achieve our debt reduction targets over time. Again, if we see the market further deteriorate, we always reserve the right to change our opinion and adjust as necessary, but we feel really comfortable in our game plan.

Yeah, I understand. I guess we can think of equity as what's left after debt from the enterprise value, but I understand the answer. My follow-up is on Grayson Mill. Rick, in your prepared remarks you talked about over a decade of inventory, and I realize there's no precision here, but we did have a substantially higher oil price when you made that acquisition, that $5 billion deal. As you look at it today at the current forward strip, how do you see the value of the forward asset versus what your planning was at the time you did the deal? I'll leave it there, thanks.

Great, thank you guys. I appreciate the answers.

Our next question comes from Phillips Johnston with Capital One. Please go ahead.

Hey, thanks. Just a clarification for Jeff on the return of capital strategy. If I heard you right, you're sticking to the 70% target, and I think you said you'd expect $200 to $300 million of buybacks each quarter to sort of get you to that 70% target at the strip. I just wanted to clarify what we might expect in an upside oil price scenario. Would we just stick to the $200 to $300 million and let the return fall below 70% in order to accelerate the reduction in net debt, or would you actually boost the absolute buyback to stick to the 70%?

Yeah, I'd answer that as I'd say we have the option to do both. Our near-term plan is to be pretty consistent. We're going to deliver a fixed dividend of, call it, $575 million annually, with the repo range that we've given, the $200 to $300 million per quarter. That's going to get you north of $1.5, $1.6 billion of cash returns to shareholders. To the extent that we deliver, as we did this last quarter, we got to the top end of the range on our share repurchase plan, any incremental cash above that we'll consider taking back to the balance sheet. But that being said, if we move back to an environment where we think we have above midcycle pricing, we'll reevaluate that thought process, maybe lean in further on the share repo, or frankly even consider the variable dividend at some point in the future again as well. But in the near term with how we look at the world, we think the fixed dividend, the share repo, leaning in on that is going to make the most sense. And then as we generate some incremental cash above that share repurchase game plan, we may take that back to the balance sheet.

The next question comes from Charles Meade with Johnson Rice. Please go ahead.

Good morning Rick, Clay, and Jeff, and the whole Devon team there. Clay, I want to go back to your prepared comments and you were specifically talking about Delaware Basin activity levels, and I think you were referencing slide six. You've addressed this a bit, but you've got a 14% improvement in drilling days year-to-date over '23. If we think about the delta in how many rigs you need to run going forward versus '24, is that number maybe a little lower than that 14% as far as keeping the same drilling footage? What do you have to run?

Well, the simple math, if you're running 16 rigs, multiply by 0.86, you get about 14, so that's where we're headed by first quarter. We don't want to get ahead of ourselves on dropping rigs too quickly, and so we're probably erring on the high side, and that's why you're seeing a little bit more days online, and certainly helps the production numbers.

Got it, okay, well thanks for that clarification. And then one question I'd like to ask, see if you want to take a stab at this, and this relates to Matterhorn. Jeff, I think you gave some good detail there about the other pipelines going in having some maintenance, because one of the big surprises was that Waha flipped — it was positive for it seemed like a couple of days and then it went right back negative again. But I wonder if you could give us an outlook on when do you think we're going to see any kind of durable return above zero for natural gas. And also maybe one of the big questions we've batted around with clients is how much, if any, incremental oil volumes come to market now that there's more gassy gas. So if you kind of take a stab at either or both of those, that would be great.

Yeah, you bet, Charles, I'll take a stab at it. I would say our perspective is we definitely think once some of the maintenance clears up on the other pipes in the basin, with the benefit of Matterhorn, you should see pricing improve. Whether that's next month or three months from now, I can't tell you. I think it's certainly going to be dependent on when that maintenance kind of clears up. As it relates to incremental volumes coming online, oil volumes or otherwise, we don't have direct line of sight to that. I can tell you we haven't changed our behavior at all as a result of Matterhorn coming online. We haven't turned on incremental wells as a result of having that additional takeaway. So specific to Devon, our behavior hasn't changed, but I certainly can't speak for other operators out there and if it's changed the way they've thought about things.

Got it. Thanks for that answer, appreciate it.

The next question comes from Betty Jiang with Barclays. Please go ahead.

Hello. Hi, a lot of questions have been asked. I just have a follow-up on the Permian. The CBR pad, the multi-well project is pretty impressive. So how big is the opportunity set to repeat these type of large-scale projects like the CBR going forward? And then as you phase in more tier-two zones, do you think you'll see any impact on the average productivity in the Permian, and how much that could extend your inventory life in the Permian?

Yeah, thanks Betty. This is one of the things we wrestle with, and I mentioned this a couple times in the prepared remarks, just around the balance of returns. If you just want to maximize the return of a well, there's one way to do that, and it's probably not going to maximize the NPV of the productivity of the overall pad. You want to maximize the NPV of the pad, you may sacrifice things like some of the overall inventory. And so there's an interesting tension between those three pieces and important factors when we think about inventory, returns, and NPV of the overall project to really maximize the opportunity. What we're thinking about is not just these incremental zones but also the spacing. In some areas we've tightened up a little bit, in other areas we've loosened up a little bit. This interplay in a three-dimensional sense of these other zones is one of the things that we've learned how to improve — some techniques, some appropriate spacings where some zones can take tighter spacings and other zones where we need to loosen up. I would say that's where we've seen productivity improvement that's outpaced our risk model going into '24, and that's probably been the most important tangible thing that we've changed, controlling the controllable kind of thing. And I think that does extrapolate going forward. Now, we have a full inventory of assets and we're always trying to drill the best stuff up front, so you're fighting the resistance of that ultimate degradation. But as you see in 2024, we didn't wait to drill some of the best wells we've ever drilled until 2024 because we wanted to hold out until then. This is the innovation of the teams and really thinking about how do we continue to do this better. And I know that there's more to come in that space to improve these future wells that on a risk basis don't look quite as good as what we drilled in the past.

I appreciate that. Maybe just on the efficiency gain standpoint, the 21-well project, these type of larger projects do allow for greater efficiency gains both on drilling and completion side. Do you see, what do you see as the average project size going forward? Is there more of these larger-size projects going forward?

You know, if we started from scratch, we would definitely do more of these. In some of our areas, what we're finding is we're feathering in after an initial development. In the 121, it was an opportunity to really develop all of these zones at the same time. Objectively, there's just not very many blank canvases to work with. But what we're finding is when we go back in, we now understand essentially the depletion effects from that prior development and how to mitigate downside from that, and then maximize the upside of some of these zones that again, objectively, we've waited later in the cycle to develop, and they continue to prove really, really productive. So I would say we tend towards larger pad development where applicable. It does provide efficiencies on drilling and completion, but much more important than the cost side of the equation is the productivity side. And as we continue to innovate and improve that productivity well to well and on an overall pad, that's where our real money is made. That's where we try to highlight really on slide five, about how much productivity we have, and really calling out this 121 that's a very large project that has just continued to exceed our expectations from all of these benches.

Our next question comes from Josh Silverstein with UBS. Please go ahead.

Thanks. Good morning guys. The Grayson Mill assets came with a big midstream footprint. How are you thinking about the value of this asset now that it's in-house? Are there opportunities or a need to expand the footprint, or could this be a potential divestiture target to accelerate the debt reduction plans?

Hey Josh, thanks for the question. As you know, we've got a lot of midstream assets inside the portfolio. I would say they're all in the portfolio for a reason, but we also remain very objective about when there's a better opportunity for the organization to exit some of these opportunities. Uniquely to Grayson, I really commended the team on the last call about the great work they've done to build this out and how it translates into higher margins and lower overall operating costs for those assets. That becomes very critical as you get into these more mature assets and you're really trying to pick up these remaining opportunities, extend the laterals, lower that cost threshold so that more and more of these opportunities meet our return threshold. So I would say they're much more likely to stay in our portfolio. In fact, I believe on the last call I highlighted an opportunity that we're going to be building some infrastructure on the east side, some of the legacy assets, to really open up some additional inventory in the Williston Basin. And with the expertise from Grayson, we feel even more confident about our ability to execute on that, bring that in, run that, and then I think it'll provide additional runway of other stranded assets to further enhance our existing footprint. So excited about those opportunities. That skill set, we're pretty objective about all of those assets. When the right time comes, you'll see us buy assets, sell assets. But specific to the Grayson assets, we're really happy that we have them in the portfolio, and it was a critical piece of our ability to transact on that deal.

Got it, that's helpful. And then within the 2025 plans, how should we think about the capital allocation to the other assets that we really haven't discussed here today — Eagle Ford, Anadarko, and the PRB? Are these just in casual harvesting mode? Is there any uptick or downtick in terms of a percentage there?

Thanks Josh, I would direct you to it's directionally looking similar. One thing that'll be a notable change, obviously with a larger Williston footprint, the overall pie will shift a little bit. You'll see higher to the Williston, you'll see the Delaware Basin drop from about 60% of the portfolio to 50%. Otherwise I would say directionally we're in the same ballpark, and we'll resist the urge to give you too much more granularity on '25 until the February call.

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