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.

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.

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.

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.

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.

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.

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

I was wondering if you could highlight some of the factors contributing to the increase in well productivity in the Delaware Basin? I know you shifted some activity from Monument Draw back to Southeast New Mexico, and I would appreciate more details on that. Additionally, what are your expectations regarding well productivity as we consider your 2025 plan?

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. 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 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.

Great. My follow-up is, you guys are six or seven weeks post the closure of Grayson Mill. I was wondering, Clay or Rick, could you identify any self-help opportunities where you think you can further enhance capital efficiency in the Bakken, specifically?

Yes. I want to emphasize that this deal stands on its own merits and is justified solely by the acquisition and its contributions to enhancing our company. We did notice some potential for synergy, and I can assure you we are poised to exceed those expectations. The team's enthusiasm is encouraging. We have already identified some immediate advantages in areas like infrastructure and our capital program. Additionally, the inventory we have retained for certain components has also provided quick benefits. We are currently making progress on various initiatives. We've capitalized on some debundling opportunities from the Devon side, and I believe there is still untapped potential on the Grayson side. The significant value lies in integrating teams that have been collaboratively addressing challenges. For instance, bringing together the experiences and insights gained from refracs will allow us to enhance our processes, not only in the Williston but also in South Texas and other key basins we operate in. We will have more updates on synergies in the future. While we may not document every instance of success, these contributions certainly add value as we integrate such a strong team from Grayson.

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

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?

Yes, Neil, that's a great question. From our perspective, we have been very consistent in our approach over the years. We will continue to seek opportunities while ensuring that we remain aware of market developments. Our team, led by David Harrison, effectively stays engaged with what's happening in the market. We often evaluate options that could strengthen our company, but we usually decide to pass on many of them and move forward. Looking at our actions over the past few years, we will keep assessing opportunities. However, it is also important to remember our focus on organic growth, such as the CBR pad you mentioned, which is another avenue for building our future inventory. We have an excellent geoscience and risk engineering team that works diligently every day. Therefore, you can expect a combined approach moving forward that includes both organic and inorganic growth. The inorganic growth could involve smaller, tactical acquisitions or larger asset purchases like Grayson Mill, which has proven highly effective for us. We have a strong team that excels in integrations. Ultimately, the key takeaway is that our strategy going forward remains aligned with what you've seen over the past couple of years.

Okay. That's great. And then my follow-up is about maximizing your natural gas realizations, especially in the Permian. You've mentioned the in-service of Matterhorn, so I'm interested in how you think that will ultimately affect Waha pricing, which has recovered but not to what might be considered fair value. Do you see a risk that this gas oversupply could shift to the Gulf Coast? Additionally, could you discuss Blackcomb and how it might address the upcoming bottleneck in Permian gas? This is a broader question about Permian gas.

Yes, Neil, this is Jeff. Yes, 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 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.

The next question comes from Kalei Akamine 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 '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?

Yes, I appreciate the attempt at another question regarding 2025, and it might not be the last one. What I would say is, let's stick with our initial guidance for now. We will provide more details in February. In the meantime, we don't want to preempt our upcoming Board meeting. This meeting is crucial, and we will discuss these matters then. We have many options and a diverse portfolio. The multi-basin approach provides us with considerable flexibility. The team continues to identify interesting opportunities to attract capital. Therefore, instead of going into too much detail at this time, we will maintain the high-level information we have shared so far.

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?

Yes, Clay, this is Jeff. That's exactly our plan. We're feeling confident about our balance sheet, which has considerable strength and liquidity. As I mentioned earlier, we're not rushing to pay off a significant amount of debt in the short term, but we do plan to work towards that. Our strategy is to address the maturities as they become due. This year, we already took care of $475 million, and we're looking at around $485 million that we'll manage in the fall of next year. Additionally, we have a term loan maturing in 2026, so we have a couple of years to gradually address that as well. Over the next two to three years, we aim to reduce our debt by approximately $2.5 billion, and we're confident in our financial flexibility to achieve this. I also want to emphasize our commitment to providing competitive cash returns to shareholders during this period.

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

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?

Yes, I believe the fourth quarter guidance is a solid starting point. We will keep refining it and looking for opportunities. You may have noticed that the transition from the third to fourth quarter shows significant variation due to workovers. We're always aiming to improve efficiency and reduce downtime, which is an ambitious objective. Typically, downtime tends to increase slightly during the winter months, and we've factored that into our fourth quarter expectations. Therefore, if you project that forward, I think it places you in the right range.

I appreciate that. I find your completion efficiencies quite impressive. How should we think about driving the next phase? What is your stance on e-frac deployment? You mentioned simul-frac, but what are your thoughts regarding e-frac deployment? Also, what are your latest insights on thermal frac? I'm curious about what could potentially enhance completion efficiency gains moving forward.

Yes, Scott, all those options are being considered. We are continuously evaluating them with an objective mindset. We constantly monitor the market to identify potential opportunities. As you know, some e-fleets required long-term contracts early on, but as the industry progresses, we believe there will be more opportunities for us to engage and see contributions to our bottom line. We remain objective regarding fuel types, with many of our fleets utilizing a high percentage of natural gas. For instance, think of an e-fleet as using 100% natural gas, while some of ours operate with about 60% to 80% natural gas, benefiting from lower natural gas prices. At the moment, being in this market has given us a competitive edge over some premium e-fleets. We're open to innovative ideas and are committed to enhancing the efficiencies created by our service partners in collaboration with our team. Honestly, I’m starting to feel uncertain about predicting when we might plateau. If you're wondering about that, your guess is as good as mine. However, I firmly believe in the creativity and innovation that our team continues to demonstrate. More updates will come, and I look forward to sharing those insights with you.

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

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?

I'll address two parts of your question. First, regarding overall productivity, particularly in Delaware, which is a significant part of our business. Over the past year, we've maintained a fairly consistent level of productivity, influenced by our geographical contributions within Delaware and the specific zones we operate in. Looking ahead, our goal is to enhance multi-zone developments, which present larger opportunities that could boost productivity. While we continually improve well placement and completion designs to maximize recovery from each opportunity, we're also focused on tightening our approach and leveraging our existing inventory effectively. This inventory is valuable and unique, so we need to balance immediate returns with long-term project value and inventory management. On a broader capital perspective, productivity, speed, and deflation are key factors. As outlined in our presentation, we have seen improvements in completion and drilling efficiencies, which lower well costs. However, working more quickly can mean pulling future activity into the current year. We've managed this by reducing rig counts while maintaining output. From our ongoing productivity and successive positive adjustments this year, we've even exceeded our internal expectations. Deflation is a backdrop we need to monitor as it could influence our capital plans. We're pleased with the results from the third quarter and optimistic about the fourth quarter. We will continue to evaluate the situation without overextending into 2025, especially considering the broader economic factors at play. Overall, we're enthusiastic about our team's ability to focus on improving drilling quality and efficiency.

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

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?

Yes, Neil, this is Jeff. Our top priority regarding cash returns is the fixed dividend. Currently, we are very comfortable with our fixed dividend given our business model, and we expect to increase it as we approach next year. After finalizing our budget with the Board, we plan to announce growth in the fixed dividend after the first of the year. This is our first priority. In addition, we have consistently indicated our preference for share repurchases over the past several quarters. We believe our equity holds significant intrinsic value currently and from a long-term perspective. Therefore, we will continue to focus on the share repurchase program. Historically, we have also paid a variable dividend, which was influenced by market dynamics characterized by above mid-cycle pricing, and it worked well for us. However, due to the recent decline in commodity prices, we believe it is more sensible to eliminate the variable dividend for the short term and intensify our share repurchases and the growth of our fixed income capital. This will be our strategic approach moving forward. Of course, if market dynamics change, we will adjust our strategy accordingly, but we feel that is the strength of our financial framework, providing us with the flexibility needed to navigate the dynamic environment we are currently facing.

Yes, we have had extensive discussions not only within our asset team but also with our business development teams. I have personally engaged with utilities and power pools to ensure that we have the right framework, structure, and support to accomplish our goals. Until we address these key issues, our efforts may not be as effective. In response to your question, we have been very active in these discussions.

Yes. I think we have a very creative team that's exploring innovative ways to connect various elements. We have significant resources in the Delaware Basin and are certainly aware of the current electricity costs and the scarcity of supply. At the same time, we're experiencing poor price realizations from our electricity sources. Bridging these gaps with our extensive capabilities presents a genuine opportunity. We are actively participating in discussions aimed at advancing this.

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

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?

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.

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?

Yes, that's a great question about inventory. We appreciate the opportunity to discuss it because it's often misunderstood. We have strong support for our numbers from third-party sources like Enverus. We are confident in having a 10-year outlook across all five of our basins, with some like the Powder River Basin even extending further. In the Delaware Basin, which is our core area, we also have a solid outlook. There is a clear distinction between the front five years and the back five years, and we have much more confidence in the early period. The overall productivity and capital efficiency for our organization look promising for that first five years, which we consider to be derisked and well-aligned with our current operations. This provides us with five additional years to innovate and improve efficiency for the latter half of that period. That's why I am so confident in our stated 10-year outlook. Moreover, there is potential beyond that timeframe, as indicated by Rick over here, who is a strong advocate for our ongoing innovations, whether it's in deeper zones or geologic adjacencies. There is still significant opportunity to explore. We mustn't overlook the remarkable creativity and determination of our teams throughout the industry; it's truly inspiring to be part of this journey, and I take great pride in it.

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

Thank you. Good morning, everyone. I think we have all been trying to understand why the stock has struggled recently. There are a couple of points you raised today that I want to address. First, Jeff, when you mention the 70% free cash return, the buybacks, and the upcoming dividend increase, I am curious about your decision to avoid the variable due to your concerns regarding commodities. Given that your capital structure still has $8 billion in debt and a backward-dated oil curve, why is the balance sheet receiving more focus than the buyback, especially considering the oil price uncertainty you discussed this morning?

Yes, Doug, we are definitely focused on the balance sheet. We've been clear about our intentions to reduce debt over time. We have the advantage of a strong balance sheet and good liquidity, along with a business model that allows for low breakeven points, so we don't feel the need to rush into aggressive debt repayment. We're trying to balance this with the value we see in our equity. As I mentioned earlier, our flexible framework enables us to pursue both goals effectively. We believe we can grow the fixed dividend, buy back our shares at what we consider a discounted price, and meet our debt reduction targets over time. If the market deteriorates further, we will reconsider our approach and make necessary adjustments, but we are quite comfortable with our current plan.

I understand. We think of equity as what remains after debt from the enterprise value, but I appreciate the answer. My follow-up is regarding Grayson Mills. Rick, you mentioned in your prepared remarks that there’s over a decade of inventory. I realize there isn’t a specific figure, but we had significantly higher oil prices when you made that $5 billion acquisition. Considering the current forward strip, how do you assess the value of the forward free cash flow asset compared to your plans when you completed the deal? I'll leave it at that.

Yes, that's a good question, Doug. The bottom line is we were around $75, $76 when we completed that transaction. It's important to always consider the long-term outlook for commodity prices. None of us have unrealistic expectations. There are people predicting $4.50 gas prices by year's end, but that seems unlikely now. Having been in this business for a long time, you know that predicting commodity prices is one of the more challenging tasks we face. However, eventually, you have to commit to a direction. What we appreciate about Grayson Mill is that we felt very confident about the economics of the transaction, particularly regarding mid-cycle prices, which may be a bit lower than current levels. We structured the deal with two-thirds debt and one-third equity. The team performed admirably, securing a fixed number of shares. Now that commodity prices have declined and equity prices have rebounded, the $5 billion headline number at the close of the transaction is closer to 4.6% or 4.7% from that perspective. This is how we see it. We are very satisfied with the transaction and optimistic about our long-term inventory. The Bakken is a fantastic reservoir, and the Williston Basin has been a significant energy source for many years. We are pleased with our position and have no regrets at all. We feel very positive about it.

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

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%?

Yes, Phil, I would say we have the flexibility to pursue both options. In the short term, we plan to maintain a consistent approach by providing an annual fixed dividend of approximately $575 million. With the share repurchase range we've outlined, which is between $200 million to $300 million per quarter, we anticipate delivering over $1.5 billion to $1.6 billion in cash returns to shareholders. Last quarter, we reached the upper limit of our share repurchase strategy. Any additional cash generated beyond that will be considered for returning to the balance sheet. However, if we enter an environment with pricing above mid-cycle levels, we will reassess our strategy, possibly increasing our share repurchases or even revisiting a variable dividend in the future. For now, given our current outlook, we believe that focusing on the fixed dividend and share repurchases is the most sensible path. As we generate extra cash beyond our planned share repurchases, we may choose to allocate that back to the balance sheet.

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

Yes. Good morning, Rick, Clay, Jeff, and the entire Devon team. Clay, I'd like to revisit your prepared remarks, especially your comments about activity levels in the Delaware Basin, which I believe relate to Slide 6. You've touched on this already, noting a 14% improvement in drilling days year-to-date over 2023. However, considering the number of rigs you'll need to operate going forward compared to 2024, do you think that number might be slightly lower than the 14% to maintain the same drilling footage? What are your thoughts on that?

If you're operating 16 rigs and multiply by 0.86, you arrive at approximately 14. That's the direction we're aiming for by the first quarter. We want to be cautious about reducing the number of rigs too quickly. Therefore, we might be slightly optimistic, which is contributing to an increased number of days online and positively impacting production figures.

Got it. Thank you for the clarification. I have a question related to Matterhorn. Jeff, you provided some insightful information about the pipelines needing maintenance, especially considering the unexpected shift at Waha. It was positive for a few days before turning negative again. Could you share your thoughts on when we might see a stable return above zero for natural gas? Additionally, we’ve been discussing with clients how much incremental oil volume might come to market now that there’s increased gas egress. If you could address either or both of those topics, it would be appreciated.

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.

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

A lot of questions have been asked. I just have a follow-up on the Permian. The multi-well project is pretty impressive. So how big is the opportunity to replicate these types of large-scale projects like the multi-well project going forward? And as you introduce more Tier 2 zones, do you expect any impact on the average productivity in the Permian? Additionally, how much could this extend your inventory life in the Permian?

Thank you, Betty. This is something we continually evaluate, as I've mentioned before regarding the balance of returns. If the goal is to fully maximize the return from a well, there’s a specific approach to take, but it might not optimize the net present value (NPV) of the overall pad’s productivity. Focusing on maximizing the pad's NPV could mean sacrificing some overall inventory. There exists an intriguing tension among these elements when we consider inventory, returns, and the NPV of the entire project to truly seize the opportunity. We're not just examining incremental zones but also their spacing. In certain areas, we have adjusted spacing tighter, while in others, we have spread it out more. This three-dimensional interaction concerning these zones has led us to refine techniques and determine suitable spacings; some zones accommodate tighter spacing while others require more loosening. We've witnessed productivity enhancements that have surpassed our risk model expectations as we move into 2024, which is perhaps the most significant concrete change we’ve implemented, focusing on what we can control. I believe this trend will continue in the future. It’s clear, as you’re aware, that we possess a full inventory of assets, and we always aim to drill the highest quality wells first. This presents a challenge as we manage the eventual decline that will inevitably occur in our prioritization. However, in 2024, we didn’t hold back from drilling some of our best wells; we accelerated their drilling out of a desire to continually improve. I am confident that innovations from our teams will further enhance future wells that may not appear as attractive on a risk-adjusted basis compared to those drilled previously.

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

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?

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.

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?

Josh, it looks like we're in a similar direction overall. However, a significant change will be seen with a larger Williston footprint. The overall distribution will shift slightly, with Williston increasing and Delaware Basin decreasing from about 60% of the portfolio to 50%. Other than that, we're largely in the same range, and we prefer not to provide too much detail on 2025 until the call in February.

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.

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