Devon Energy Corporation (NYSE:DVN) Q3 2024 Earnings Call Transcript

Devon Energy Corporation (NYSE:DVN) Q3 2024 Earnings Call Transcript November 6, 2024

Operator: 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 Ms. Rosy Zuklic, Vice President of Investor Relations. You may begin.

Rosy Zuklic: Good morning, and thank you for joining us on the call today. Last night, we issued Devon’s 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 Investors 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 Ritenour, 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.

Rick Muncrief: Thank you, Rosy. I appreciate everyone taking time to join us this morning. Let’s begin on Slide 2 by covering a few of our third quarter key highlights. Once again, we delivered strong operational and financial results, driven by the continued focus on executing our strategic plan. We reached an all-time quarterly record of total production averaging 728,000 barrels of oil equivalent per day, including 335,000 barrels of oil per day. Our production has surpassed guidance expectations every quarter this year. In the Delaware Basin, well productivity was strong once again this period. And across all five basins, we delivered another solid base production performance. On a production per share basis, this represents a 12% year-over-year growth.

With the operational performance in our recently closed acquisition, we’re pleased to be able to raise our full year production guidance again for this year. We now expect to produce about 730,000 BOE per day for 2024, an increase of 12% to this year’s budget. This phenomenal performance enabled us to generate $786 million of free cash flow in the third quarter and return $431 million of it back to shareholders. We leaned in heavier on our share repurchase program, and we continue to think reinvesting in our company at today’s prices is the right thing to do for shareholders. We also closed the Grayson Mill transaction very quickly. This acquisition enhances our position as one of the largest producers in the U.S., with average daily oil rates estimated at around 380,000 barrels per day.

In the Williston Basin, our production will nearly triple, and we have extended our resource depth, giving us about 10 years of inventory at current activity levels. We successfully accomplished these things during a very volatile market backdrop. We remain focused on the things we could control. With our high-quality portfolio, strong balance sheet and disciplined business model, we are positioned to succeed through a variety of commodity cycles. We don’t have a crystal ball to know where commodity prices will be in the short term, but continue to be very constructive on oil and gas and believe that the world will continue to need all forms of energy. Now moving on to Slide 3 to talk about where we will focus in 2025 to successfully continue to execute our strategy.

We remain committed to operating excellence and will continue to look for innovative ways to improve our capital efficiency. We believe our multi-basin portfolio in the top U.S. resource plays is superior to most and provides us with over a decade of low-risk development inventory. We will continue to look for opportunities to further enhance our portfolio and grow our resource base. To succeed in our business, we need to maintain our financial strength and flexibility. We will remain disciplined in our approach to maximize free cash flow and are committed to having low leverage. And we’re focused on delivering value to our shareholders through dividends and share buybacks. Now 2025 is shaping up to be an exceptionally strong year for Devon.

With the Grayson acquisition, we are well positioned to deliver healthy growth in oil and expect robust free cash flow, even in a lower commodity environment. Our legacy portfolio in key U.S. basins will provide a solid foundation for us to continue the momentum that we have demonstrated so far this year. As a result, Jeff will be providing preliminary 2025 guidance that is actually better than we had previously communicated. Now before I hand the call over to Clay, I want to thank all of the Devon employees and contractors who challenge themselves daily to come up with innovative ways to create value for our company. I also want to thank the team working on the integration of Grayson Mill. I’m excited to see the results from teams sharing best practices.

And with that, I’ll now turn the call over to Clay.

Clay Gaspar: Thank you, Rick, and good morning, everyone. Turning 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 win 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 throughout 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 ’25 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 Wolfcamp 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 highlighted one of the primary contributors from this quarter, the CBR 12-1 development.

This project co-developed the Wolfcamp A, Wolfcamp 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 CBR 12-1 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, 12-1 gives us additional confidence of this winning strategy. Our team continues to derisk 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 multiyear runway of outstanding performance from the Delaware Basin. Turning to Slide 6. We’ve seen our Delaware Basin well productivity outpace 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 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 in 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 2- and 3-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.

Jeff Ritenour: 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 cost improving 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 dividend 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-EBITDA ratio of just over 1x 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 pay down 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 BOEs 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 million to $300 million each quarter and we’ll 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 Rosy for Q&A.

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

Q&A Session

Operator: Thank you. Our first question today comes from Arun Jayaram with JPMorgan. Arun, please go ahead.

Arun Jayaram: 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 Draw back to Southeast New Mexico. And maybe — love to get more details on that. And what you’re underwriting in terms of well productivity as we think about your 2025 plan?

Clay Gaspar: Arun, it’s Clay. Thanks for the question. First, let me reiterate, the ’25 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 the 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, stamping 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.

nd 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 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 this 12-1, 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.

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

Clay Gaspar: Yes. As a reminder, this deal was built on its own merits and justified just on the acquisition and what it really does to make us a better company. We did identify a little bit in the synergy bucket. I can tell you we’re going to blow that away. We feel really good about what we’re seeing from the excitement from the team. Some instant wins we found in things like infrastructure and capital program. And even the inventory that we held in place on some parts and pieces, those have been some really instantaneous wins. Things that we’re working on in progress right now. There’s some debundling opportunities that we have taken full advantage of on the Devon side that I still see as unlocked potential on the Grayson side.

And then I think the real upside potential — and this is hard to quantify really in synergies, but think about the value of having teams that have been working problems side by side. And when you bring them together, take for example, the refracs, and all that experience and that wisdom coming together to really figure out how do we do it better. And not just better in the Williston, but better in South Texas and better in the other amazing basins that we have. So more to come on that in synergies. We probably won’t tally it up every time we have one of these wins, but that’s certainly an accretive part of the value proposition when you bring in such a strong team as we did with Grayson.

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

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

Rick Muncrief: Yes, Neil, that’s a great question. And I think from our perspective, our commentary has been very, very consistent over the last several years, and that is we’ll continue to look for opportunities, make sure that we’re not missing something. We’ve got a team that — David Harrison, his folks do a really nice job in staying plugged in with what’s in the market and what’s out there. We debate internally on things that could make us a stronger company. More often, we just pass on it and move on down the road. But — so that’s something. I think if you look at our actions over the last couple of years, we’ll continue to evaluate things. But don’t forget the organic piece, too, and that’s some things. And Clay, you talked about the CBR pad, that’s another way.

We’ll continue to build inventory for the future organically. We’ve got a great geoscience team and a risk engineering team that works very hard day in, day out. And so, I think that you’ll see a combo path forward, and that is the organic and inorganic. And the inorganic could be a — common — the smaller just ground game type — tuck-in type small deals, or something that’s more of an asset like you saw with Grayson Mill, which once again, works very, very well for us. And so, we have a strong team. It does a good job with integrations. And I think that’s — but the bottom line, the key takeaway is the same path going forward is what you’ve seen over the last couple of years.

Neil Mehta: Okay. That’s great. 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 is — it 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 can also talk about Blackcomb and how that resolves potentially the next bottleneck in Permian gas too? So broader Permian gas question there.

Jeff Ritenour: Yes, Neil, this is Jeff. Yes, as you know, we obviously have a commitment on Matterhorn and have an equity contribution there is as well. We’re excited that the pipe is up and going and flowing 2 Bcf a day 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, call it, 90% of our molecules flow 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 has done a great job and got out in front of that. We’ve taken capacity away from Katy over into the Louisiana LNG 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 pipe there in the Permian Basin 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 in some of this maintenance settles out. We expect that to continue and are realizing pricing going into the fourth quarter. And certainly into 2025, we expect to improve over time.

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

Kalei Akamine: Good morning, guys. Thanks for getting me on. For my first question, I’m also going to take a shot at ’25. You kind of addressed the Permian piece of the puzzle, that there is 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 ’25 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 ’25?

Clay Gaspar: Yes. I appreciate — this is Clay again. I appreciate the attempt at another ’25 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’ll 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.

Kalei Akamine: Fair enough. For my follow-up, just kind of thinking about debt reduction. In September, you made a first go at your $2.5 billion target and taking out the $500 million. In the next several years before ’28, you’ve got about $2 billion coming due. In the base case, do you take those out as they come due?

Jeff Ritenour: Yes, Clay, this is Jeff. Yes, 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 to take out the maturities as they come due. We — 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 of years to start chipping away at that over time as well.

So, over the next two to three years, as we’ve highlighted, we’d like to get kind of roughly $2.5 billion of absolute debt out, but we’re — 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 time frame as well.

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

Scott Gruber: Yes. How should we think about your LOE and GPT costs going forward post close? We got the 4Q guide. Is there an opportunity to squeeze OpEx lower? Or should we use the 4Q guide as the baseline for ’25?

Clay Gaspar: Yes, I think the 4Q guide is a good starting point. Again, we’ll continue to refine that, look for opportunities. You might have noticed the 3Q to 4Q 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 in the — certainly in the right ballpark.

Scott Gruber: Okay. I appreciate that. And then just thinking about your completion efficiencies, quite impressive. How should we think about — what do 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 — as you’re looking at something like thermal frac. Just kind of what drives the — what could drive the next leg of completion efficiency gains?

Clay Gaspar: 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 kind of 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 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 — maybe a little bit secondary to some of the premium e-fleets. So far, it’s been our competitive advantage or advantageous for us to stay in the direction we’re in. But I guarantee you, we are wide open to creative ideas, continue to innovate the efficiencies that our service companies, partners. Create right alongside with our team is pretty remarkable. And I’m getting tired of trying to outguess them on is this the time that we plateau. So, if you’re thinking about when do we plateau, your guess is good as mine. But I’m going to bet on the over on the creativity and the innovation that these folks have, and they continue to apply. So more to come on that, and I look forward to sharing with you.

Operator: Our next question comes from Roger Read with Wells Fargo. Please go ahead.

Roger Read: Yes. 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 cost as you think about it?

Clay Gaspar: Yes, Roger, I’ll take kind of two parts. First, on the overall productivity, and let’s just focus on the Delaware because that’s such a large piece of our business. When I look back year-to-year productivity, we’ve been in a band — and it’s a relatively tight band, but it certainly is affected by our geographic contribution inside of the Delaware. Also, the zonal contribution, how much of which zones do we do. And then going forward, our ability to move more of these multi-zone developments, a little bit larger development opportunity set that also contributes to that productivity. So, while we’re doing things to better land the wells, always trying to tweak the completion design to eke out a little bit more recovery factor on each of these opportunities, there’s also some kind of technical attention on maybe we need to tighten a few more of these up and really lean into this inventory opportunity and not miss these.

We all know that this is incredibly precious inventory that doesn’t exist really anywhere else on the planet. And so, we want to make sure that we’re thinking about the balance of near-term returns, the ultimate net present value of the project, but also the inventory considerations. Shifting over to the bigger capital picture. I think about that productivity as part of the equation. Speed is part of the equation, and then deflation is part of the equation. And so, you think about those three inputs, we highlight on Slide 6, the completion efficiencies and drilling efficiencies. That actually — obviously, on a per well basis, makes those wells cheaper, but it works a little bit against you because you’re working faster and you’re pulling more of next year’s activity into this year.

We’ve mitigated that by dropping rigs, lowering kind of headline number activity, still getting the same output. But as you see from our productivity and our continued beat and raise throughout the year, that productivity gains combined from the well productivity and from the more wells online, we’re outrunning even our internal estimates. The deflation is kind of out there in the background. And the question is, is that going to take up enough to keep our capital in line. We saw a really good result in the third quarter. I think we’re really pleased on what we’re seeing in the fourth quarter. We’ll continue to watch that. We don’t get too far ahead of ourselves into ’25 with all the macro things that are going on. So, a lot going on as we think about ’25, all of that stuff comes into play but really excited about what the team is controlling the controllables on drilling better wells and doing it in a more efficient manner.

Operator: Our next question comes from Neal Dingmann with Truist. Please go ahead, Neal.

Neal Dingmann: My first question, likely for Rick, for you or 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 dip going forward? And then secondly, on the recent buybacks, did that include any PE shares and would you all consider in stepping a larger way into buybacks if any of the PEs decide to sell?

Jeff Ritenour: Yes, Neil, this is Jeff. So, first priority for us on the cash return 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 a 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. So, we think there’s great value in our equity today from an intrinsic value standpoint and kind of our view of the long term.

So, you’re going to continue to see us lean in on the share repurchase program. I think 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 that we’re seeing with what we would characterize as above mid-cycle pricing. We think it worked incredibly well for us. Now with the pullback that we’ve seen 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 FIC. 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 — we really feel like is the beauty of our financial framework is that provides us all the flexibility that we need to kind of manage through the dynamic environment that we’re all living in.

Neal Dingmann: Yes, I like that game plan, Jeff. And then just secondly, Rick, for you or Clay, just a broader on potential future JV plans. I mean, simply, it seems like some of your peers have started talking about power and nuclear, I’m just wondering if you all started any of these conversations for any potential JVs with these type of plants?

Rick Muncrief: Yes, absolutely, Neal. We had a lot of discussion or — not only our asset team, our business development teams have had a litany of discussions. But I can also tell you that what I’ve personally been involved with is talking to 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. So, but to answer your question, yes, we’ve been very, very engaged in discussions.

Clay Gaspar: Yes. And the follow on that as well. I think there’s — you know 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 electricity. And at the same time, we have the source of that electricity that is getting terrible price realizations. And so, 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.

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

Paul Cheng: Clay, just curious that as you are trying to do more cut 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?

Clay Gaspar: Thanks for the question, Paul. As we move generally down in section, generally speaking, it gets gassier. So that’s no great surprise. I would say we’ve actually seen some upside to the oil cut and some of the, what we call B200, B300 benches that have really proven a lot oilier. We’ve got a couple of tests that we’re doing our first half of this year that we’re pretty excited about even deeper benches. We have done a whole lot of geologic mapping and science work, oil fingerprinting, really understanding where those opportunities are to really drill deeper, include more of these deeper benches and still keep our oil cuts up. And 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. So, we’re obviously very aware of that. Specific to the HUS, 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 that. We’ve got third-party midstream partnerships that are very engaged in that pretty much throughout that stack of rocks. And so, it’s not something that typically surprises us. We’re very aware of that. We certainly take that into account and make sure that we have the appropriate safety and midstream infrastructure in place as we dig into that area.

Paul Cheng: And Clay, the second question is then on inventory backlog. Now that we have Grayson, I think you’re saying that you have a 10 year of inventory life on that. And how about in the Permian? If we look at using a, say, call it, $50 WTI and $3 gas price, what is your inventory license? How many wells do you need in the Permian per year in order for you to sustain the operation?

Clay Gaspar: Yes. 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, as 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, we feel very good about that front five years derisked and really kind of some really good continuity to what we’re doing today.

That just gives us five years to continue to innovate and get more efficient on that back five. And that’s how — that’s why I feel so confident about the 10-year runway that we talk about. 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 to that in a business sense and adjacencies in the sense of 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 — it’s so exciting to be part of, and I’m so proud to see it.

Operator: Next question comes from Doug Leggate with Wolfe Research. Please go ahead, Doug.

Doug Leggate: 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. And 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% free cash return and buybacks and you’re going to raise the dividend. But at the same time, you’ve avoided the variable because of your concerns over the commodity. Well, your capital structure still get $8 billion of debt in a backward-dated oil curve. Why is the balance sheet now getting more attention than a buyback, given the uncertainty that you — yourself laid out this morning on the oil price?

Jeff Ritenour: Yes, Doug, we can — we absolutely have a focus on the balance sheet. So, 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 that we have and the liquidity that we have and the business model that we pursue with the low breakevens that we don’t have to rush out and act like something’s wrong with the balance sheet, right, and be aggressive in some sort of debt pay down. We’re trying to balance that with the value that we see in the equity, right? So, as I mentioned earlier, we feel like the flexibility of our framework allows us to do both, honestly. So, 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.

Doug Leggate: I understand. I guess we kind of think of equity as what’s left after debt from the enterprise value, but I understand the answer. My follow-up is on Grayson Mills. Again, 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 free cash flow forward asset versus what your planning was at the time you bought — you did the deal? And I’ll leave it there.

Rick Muncrief: Yes, it’s a good question, Doug. I mean the bottom line is we were about $75, $76, as I recall, when we did that transaction. And it’s — I think you have to always think long term about what the commodity price is going to be. And none of us — as I said, none of us have rose-colored glasses. There’s people who have been calling for $4.50 gas price by the end of this year. That doesn’t look like that’s going to happen either. So, it’s — and you’ve been in this business a long time as well. And it’s — picking the commodity price is probably one of the trickier things that we do. But eventually, you have to put a stake in the ground and say this is where we’re going to head. And what we like about Grayson Mill is that the economics around of that transaction, we felt very, very good about a mid-cycle pricing or probably a little bit cheaper than or lower than where we are today.

So, we felt very good about it. We structured the deal to be 2/3 debt, 1/3 equity. And we had the — I think the team did a really good job. We locked in a set number of shares. Now the commodity prices pull back, equities prices come back. And so, what the $5 billion headline number is actually when we closed the transaction, was we’re probably closer to 4.6% or 4.7% when you think about that standpoint. So, kind of how we look at it. So, we feel really good the transaction. We feel really good about the long-term inventory. As you know, the Bakken is a great reservoir. Williston Basin has been a tremendous provider of energy for a long time. So, we really like the position we’re at. So, I can tell you, we have no regrets whatsoever. And so, we feel really, really good about it.

Doug Leggate: Appreciate the answers.

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

J. Phillips Johnston: 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 million 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 you stick to the $200 million 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 buy back to the 70%?

Jeff Ritenour: Yes, Phil, the way I’d answer that is 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 a year. With the repo range that we’ve given, the $200 million to $300 million over time, a quarter, that’s going to get you north of $1.5 billion, $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 repo game 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 mid-cycle 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 kind of 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 repo game plan that we’ve laid out, we may take that back to the balance sheet.

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

Charles Meade: Yes. 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 6. So, you’ve addressed this a bit. So — but you’ve got a 14% improvement in drilling days year-to-date over ’23. But if we think about kind of the delta in your — 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 to keep the same drilling footage, what do you have to run?

Clay Gaspar: 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’re probably — we don’t move this — 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.

Charles Meade: Got it. Okay. Well, thanks for that clarification. And then one question I’d like to ask, this is — see if you want to take a stab at this and this relates to Matterhorn. So, Jeff, I think you gave some good detail there about the pipelines going into 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 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 that we’ve added around with clients is how much if any, incremental oil volumes come to market now that there’s more gas egress? So, if you kind of take a stab at either or both of those would be great.

Jeff Ritenour: Yes, you bet, I’ll take a stab at it. I would say our perspective is we definitely think once some of the maintenance cleans 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, and 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.

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

Betty Jiang: A lot of questions has been asked. I just have a follow-up on the Permian. The CBR — 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 2 zones, do you think you will see any impact on the average productivity in the Permian? And how much that could extend your inventory life in the Permian?

Clay Gaspar: Yes. Thanks, Betty. This is one of the things we wrestle with, and I mentioned this a couple of 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. If 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 kind of pieces and important factors when we think about inventory, returns and NPV of the overall project, to really maximize the opportunity. And so, 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. But really, this interplay in a three-dimensional sense on 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 a little tighter spacing and other zones where we need to loosen up a little bit. 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 there’s no doubt about it. I mean, Betty, you know this as well as anybody. We have full inventory of assets, and we’re always trying to drill the best stuff upfront.

And so it’s kind of that you’re fighting the resistance of that ultimate degradation that we will all see in this prioritization. But as you see in 2024, we didn’t drill — we didn’t wait to drill some of the best wells we’ve ever drilled until 2024 because we wanted to really 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 just — don’t look quite as good as what we drilled in the past.

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

Clay Gaspar: 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. And so, in the 12-1, it was an opportunity to really develop all of these zones at the same time. Objectively, there’s just not very many blank campuses 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 completions. 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 in an overall pad, that’s where our real money is made and that’s what we try to highlight really on Slide 5. Yes, slide 5 about how much productivity we have and really calling out this 12-1. It’s a very large project that has just continued to exceed our expectations from all of these benches.

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

Josh Silverstein: The GME assets came with the 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?

Clay Gaspar: 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. I would say uniquely to Grayson. I really commended the team on the last call about the great work that 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 will provide additional runway of other stranded assets to further enhance our existing footprint. So excited about those opportunities, that skill set. I would say we’re pretty objective about all of those assets. When the right time comes, you’ll see us buy assets, sell assets. But I would say specific to the Grayson assets, we’re really happy with what we have them in the portfolio, and it was a critical piece of our ability to transact on that deal.

Josh Silverstein: 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 assets just in cash flow harvesting mode? Is there any uptick or downtick in terms of percentage there?

Clay Gaspar: Josh, I would direct you to — it’s directionally looking similar, okay? One thing that will 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 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.

Rosy Zuklic: So, we have met our time commitment. I want to thank everyone for your interest in Devon. And if you have any further questions, please reach out to Chris or me. Thank you again for joining us on our call today.

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