Good morning, and thank you for joining us on the call today. Last night, we issued an earnings release and presentation that cover Devon's results for the first quarter and our outlook for the remainder of 2024. Throughout the call today, we will make references to the earnings presentation to support prepared remarks, and these slides can be found on our website. Also joining me on the call today are Rick Muncrief, our President and CEO; Clay Gaspar, our Chief Operating Officer; Jeff Ritenour, our Chief Financial Officer; and a few other members of our senior management team. Comments today will include plans, forecasts, and estimates that are forward-looking statements under U.S. securities law. These comments are subject to assumptions, risks, and uncertainties that could cause actual results to differ materially from our forward-looking statements. Please take note of 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, Scott. It's great to be here this morning, and I appreciate everyone joining us. Devon has achieved exceptional results in the first quarter, exceeding our operational and financial targets significantly. This positive start to 2024 showcases the strong momentum we've quickly established, setting the stage for continued business growth. I want to extend my gratitude to our employees, service providers, and infrastructure partners for their contributions in getting 2024 off to a solid start. In my comments today, I will highlight the reasons behind our first quarter outperformance and the factors driving our improved outlook for the rest of the year. Let's begin with a quick overview of our first quarter results, which include several key highlights. First, our production volumes were about 4% higher than anticipated, averaging 664,000 BOE per day. This production increase was primarily due to three significant factors. The first was the strong well productivity from over 100 wells that came online during the quarter, with these high-impact wells performing better than expected in the Delaware Basin. This year, we achieved initial production rates that were more than 20% higher than last year's. I believe that these strong recoveries will continue as we move through the year. The second factor contributing to the increased production was the enhanced cycle times achieved in our drilling and completion operations. Clay will provide more details later, but these efficiency improvements allowed us to accelerate our activity and increase the number of days we were operational compared to our initial plan. The third factor was the reduction of infrastructure constraints in our Delaware Basin assets, thanks to investments in additional gas processing, compression, water handling, and electrification made in collaboration with our partners. These important capacity improvements have enabled us to ensure better run times for our base production and increase our activity in this world-class basin. Additionally, our team demonstrated effective cost management by delivering operating costs that were 3% lower than our guidance and maintaining capital expenditures in line with expectations, even as we increased our activity pace. This strong start positions us well for improved cost efficiency in 2024, especially as we potentially benefit from deflationary trends throughout the year. Focusing on the bottom line, our comprehensive execution of the plan resulted in our 15th consecutive quarter of free cash flow, highlighting the resilience of our strategy to create value consistently. Through this free cash flow, we continue to reward shareholders with our cash return framework, which emphasizes stock buybacks and strong dividend payouts. As we move to our updated guidance, I'm pleased to announce that due to our strong operational performance year-to-date, we are raising our expectations for the full year of 2024. Our production target is now increased by 15,000 BOE per day to a new range of 655,000 to 675,000 BOE per day. This adjustment reflects our confidence in the well performance we've seen so far and the promising projects lined up for the year. Importantly, we will achieve this additional production within our original capital budget of $3.3 billion to $3.6 billion, which is expected to maintain a steady production profile with around 10% less capital than last year. This fully funded program operates at a low breakeven of around $40 per barrel, one of the lowest rates in the industry. With our enhanced outlook for the year, we are on track to generate over 15% more free cash flow in 2024 compared to last year at current pricing levels, resulting in an attractive free cash flow yield of 9%, significantly higher than the broader market. With our growing free cash flow, we remain committed to maintaining capital discipline while rewarding shareholders with increased cash returns. Our flexible cash return strategy will direct free cash flow towards the most promising opportunities, focusing on share buybacks to capitalize on the excellent value Devon presents at these historically low valuations. In summary, 2024 is off to an outstanding start. We have exceeded our commitments in the first quarter. Our business continues to improve and gain momentum, which is reflected in our upgraded outlook. Given current market valuations, the most advantageous move is to repurchase our stock and capture this value. We look forward to a successful year ahead for Devon, and our team is enthusiastic about building on this strong beginning. Now, I will turn the call over to Clay.

Thank you, Rick, and good morning, everyone. Devon's first-quarter outperformance was the result of strong operational execution across the board, where each asset team delivered results that exceeded targets for production and capital efficiency. As Rick touched on, the great start of the year was underpinned by three key factors: excellent well productivity, improved cycle times, and outstanding base production results. For the remainder of my prepared remarks, I plan to cover asset-specific highlights that are driving this positive business momentum and provide insights and observations that drive Devon's improved outlook for 2024. Let's begin on Slide 7 with an overview of our Delaware Basin activity, which accounted for 65% of our capital investment for the quarter. We operated a program of 16 rigs and 4 completion crews across our 400,000 net acre position in the play, resulting in production growth of 5% compared to the same period last year. This volume growth was driven by 59 new wells brought online that predominantly targeted the Wolfcamp formation. In aggregate, these high-impact wells achieved average initial flow rates of more than 3,200 BOE per day. This performance results in the best well productivity from our Delaware Basin assets in more than 2 years. On Slide 8, while we delivered high economic results across the basin, I'd like to drill down on three impressive projects that were the biggest drivers of our outperformance for the quarter. On the far left side of the slide, Devon's largest development area in the quarter was the 13-well Van Doo Dah project in our Cotton Draw area of Lea County. With thoughtful upfront planning and improved efficiencies from our simul frac operations, the team brought Van Doo Dah online nearly 2 weeks ahead of plan. The massive scale of this project was showcased by the peak flow rates that reached nearly 30,000 gross barrels of oil per day. This success further reinforces why I believe the STACK pay potential in Cotton Draw to be one of the best tranches of acreage in all of North America. Another noteworthy project that achieved the highest initial rates of any project in the quarter was a CBR 15-10 in our Stateline area. This 3-mile Upper Wolfcamp development was made possible by an acreage trade and recorded average 30-day production rates of 5,600 BOE per day. Very few projects in the history of the Delaware Basin have reached this level of productivity, and the expected recovery from this project is also extraordinary, projected to exceed 2 million BOE per well. Lastly, I would like to cover a key appraisal success that we had in the quarter in the Wolfcamp B interval of our Thistle area. This proof-of-concept well came in significantly above our predrill expectations, with peak rates for the single appraisal well exceeding 5,000 BOE per day. This positive result adds to our resource depth in the Delaware by derisking approximately 50 locations in the area. While the hydrocarbon stream in the deeper Wolfcamp intervals generally shifts towards the higher gas rates, the oil cuts are strong enough for this opportunity to compete very effectively for capital in our portfolio. Given this, we expect to incorporate more Wolfcamp B wells into our future multi-zone developments as we plan for our 2025 program and beyond. Turning to Slide 9, we are clearly off to a great start with our 2024 plan in the Delaware. As you can see on the left, our well productivity is on track to materially improve year-over-year. As a reminder, this improvement is driven by returning to a higher allocation of capital to New Mexico, where our inventory depth is the greatest. It is important to note that we have not changed spacing or lateral length to achieve these improvements. Importantly, as you can see to the right of this slide, we're also pairing this with improved well productivity in the Delaware Basin with efficiency gains. The adoption of simul frac across the broader segment of our activity has been a key driver of compressed cycle times, but the high-grading of rig fleets is also driving down overall well costs. I want to congratulate the teams for this success and expect this momentum in the Delaware to continue as we work our way through the year. We included Slide 10 to remind everyone of the recent infrastructure build-out that we either led, participated in, or are benefiting from. Our patience in giving this highly prolific area some breathing room for this infrastructure to mature was the right decision from an economic perspective as well as an environmental standpoint. Slide 11 is an updated view of Enverus's remaining inventory of the top Delaware Basin producers. As you can see from this credible third-party perspective, we have one of the largest inventories among operators in the basin, providing us with a multi-decade resource that will drive enterprise-wide performance for many years to come. While the Delaware Basin is the driving force behind our performance, we do value a diversified portfolio across the very best oil and liquids-rich basins in the United States. I would also like to briefly highlight a few items from those basins. In the Eagle Ford, the steps we have taken to tighten our capital efficiency are yielding results. In the first quarter, we brought online 26 infill wells and a handful of highly successful refracs that resulted in an oil growth rate of 7% year-over-year. Importantly, we're able to deliver this growth while spending 13% less capital versus the average run rate of 2023. This improved capital efficiency is driven by less appraisal requirements to tactically advance our redevelopment of the field, along with the benefits of a more balanced program across our assets in DeWitt and Karnes counties. In the Williston Basin, production increased 9% in the quarter. This performance exceeded our internal expectations due to excellent well productivity in the core of the play from our Bull Moose and North John Elk projects and better uptimes from our base productions. For the full year, the oil-weighted production stream for this asset is on track to generate up to $500 million of cash flow for the company. Moving to the Powder River Basin, our activity in 2024 is designed to build upon the well productivity gains we achieved last year, where our 9 Niobrara wells increased flow rates by 20% from historic levels. For the rest of 2024, we plan to bring online around 10 Niobrara wells across our acreage in Converse County. The objective of this activity is to refine our view on spacing and optimize completion designs to drive down costs as we advance this area towards full field development. Lastly, in the Anadarko Basin, with the recent weakness in gas prices, our capital activity was limited to one project placed online in the first quarter, but the flow rates were very impressive. The Allen pad that co-developed both the Meramec and Woodford formations achieved peak cumulative rates for this pad of 5 wells exceeding 20,000 BOE per day, with liquids comprising nearly 40% of the production mix. As we look to the rest of 2024, we're reducing activity to 2 rigs in our Dow JV area and intend to bring online the majority of the activity in the second half of the year to capture the higher gas prices expected in the winter months. In summary, I'm proud of the capital-efficient results that our team has delivered this quarter and the strong momentum that we have built as we look to execute on our plan over the remainder of the year and beyond. And with that, I'll turn the call over to Jeff for a financial review.

Thanks, Clay. I'll spend my time today covering the key drivers of our first-quarter financial results and provide some insights into our outlook for the rest of the year. Beginning with production. We had very strong results across the board in the first quarter, driving our improved full-year outlook. Looking specifically at the second quarter, we expect this production momentum to continue with volumes increasing to a range of 670,000 to 690,000 BOE per day. This expected growth is driven by higher completion activity in the Delaware Basin, resulting from the fourth frac crew we put to work at the beginning of the year in the core of Southeast New Mexico. On the capital front, we remain confident in our guidance range for the full year. Spending will be slightly skewed to the first half of the year, roughly 55% of our budget, due primarily to the cadence of Delaware completion activity. This spending will begin to moderate as we move from 4 to 3 frac crews in the Delaware, resulting in a lower capital spending profile in the second half of the year. With regard to pricing, the recent strength in the price of oil has provided a meaningful impact on our returns and cash flow generation capabilities. For every dollar uplift in WTI, we generate around $100 million of incremental annual cash flow. On the gas side, we are experiencing weakness in WAHA pricing within the Permian. But as a reminder, our exposure is limited, given our firm takeaway and basis hedging. Looking ahead, we expect the situation to improve with the Matterhorn pipeline scheduled to come online later this year. Moving to expenses. We did a good job controlling field-level costs during the quarter. Our lease operating and GP&T costs totaled $9.27 per BOE in the quarter, coming in below the bottom end of our guidance range. Looking ahead to the rest of the year, we expect our field-level costs to remain relatively stable, and we feel very comfortable with our full-year guidance ranges. Moving to the bottom line. We generated $1.7 billion of operating cash flow during the quarter. This level of cash flow funded all capital requirements and resulted in $844 million of free cash flow for the quarter. With this free cash flow, we continue to prioritize share repurchases in the first quarter. We repurchased $205 million of stock in the quarter, bringing our total activity to $2.5 billion since the program's inception in late 2021. With a $3 billion authorization in place, we have plenty of runway to compound our per-share growth as we work our way through the year. In addition to our buyback program, another key use of our excess cash in the quarter was the funding of our fixed plus variable dividend with the board declaring a payout of $0.35 per share. This distribution will be paid at the end of June. To round out my prepared remarks this morning, I'd like to give a brief update on our investment-grade financial position. In the first quarter, our cash balances increased by $274 million to a total of $1.1 billion. With this increased liquidity, Devon exited the quarter with a very healthy net debt-to-EBITDA ratio of 0.7x. Looking ahead, with the excess free cash flow that accrues to our balance sheet, we plan to build liquidity and retire maturing debt. Our next debt maturity comes due in September of this year, totaling $472 million, and we'll have the opportunity to retire another $485 million of notes in late 2025. And with that, I'll now turn the call back over to Rick for some closing comments.

Thank you, Jeff. To wrap up our prepared remarks this morning, I want to reinforce a few key messages. Number one, we're delivering on exactly what we promised to do and then some in the first quarter. Our disciplined execution and outperformance of the plan demonstrates the momentum that we've established, setting the stage for our business to strengthen as we go through the year. Secondly, with this great start to the year, we're raising our 2024 production guidance. This improved outlook is underpinned by efficiency gains from excellent well productivity, faster cycle times, and better base production results, anchored by our franchise asset in Delaware. Number three, furthermore, this improved outlook is also manifesting in higher free cash flow that will translate into higher cash returns for our shareholders. Given the value proposition that we offer, the best thing we can do is prioritize repurchasing our shares. Lastly, our long-duration resource base is one of the deepest of any company out there. We continue to find ways to add resources. You heard some of that this morning. This was evidenced by our continued success in Wolfcamp B, positive redevelopment results in Eagle Ford, and productivity breakthroughs in the Powder River Basin. And with that, I'll now turn the call back over to Scott for Q&A.

Thanks, Rick. We'll now open the call to Q&A. Please limit yourself to one question and a follow-up. This will allow us to get to more of your questions on the call today. With that, operator, we'll take our first question.

Our first question comes from Arun Jayaram with JPMorgan.

Team, could you provide more details on the improvements in the midstream operations in the Delaware Basin? Also, is there any caution factored into the second-half guidance, considering your strong performance in the first quarter despite the weather challenges?

Yes, Arun, I think you're alluding to the infrastructure spend that we had last year, which has cleared up a lot of the gas processing bottlenecks and some of the other challenges that we had around water movement and electricity. The team has done a great job of getting ahead of that. We're spending, call it, $100 million to $115 million a year in the Delaware to build out that compression and gathering. And as Clay mentioned in his prepared remarks, that served us really well as we walked into 2024 and has freed up a lot of capacity and availability for us to move the molecules. As it relates to the back half of our guide, we still feel really comfortable with the guide that we've laid out. We've gotten good progress, obviously, here in the first quarter. We'll continue to monitor things as we progress and provide you guys with updates as we move ahead. But needless to say, we feel really good about how things are working operationally in the basin and frankly, across all of our core areas.

Great. And maybe one for Clay. Clay, you highlighted how you're seeing good performance from the refrac program in the Eagle Ford. I was wondering if you could shed some more light on what types of returns that you're seeing from the refrac program, maybe relative to primary development? And do you see an opportunity here in the Eagle Ford as well as in the Bakken for more of this type of activity?

Yes. Thanks for the question. It is becoming a more core piece of what we do. I think this is on the back of years of trying to figure out what's working, what's not when you post appraise and kind of look at industry performance. I would say we've got a lot of mixed results. When you start fine-tuning a little bit and look at more recent performance, some of the work that we're doing, you see some really encouraging results. And that's on the back of making sure that we understand the well construction, the opportunity from a geology standpoint, that initial completion design, and really focusing on the best opportunities. I would say the wells that we are putting online this year, approximately 25 refracs, compete very favorably with the wells that we're drilling on a heads-up basis new well construction. So I’m very encouraged about what we're seeing, and I think there's more runway to go. On the Williston Basin, I would characterize the Williston as a little earlier in the process. Again, you draw a big circle around the Williston, you post appraise what the refracs look like. I think it's a little bit more of a mixed bag. I'm still highly encouraged. I mean, in every one of these very prolific basins, we're still recovering a very small amount of the total resource in place. And I'm very encouraged about where we sit in a multi-basin resource play company in some very high-quality opportunities to continue to get smarter on how we create value from these amazing opportunities. So more to come on that.

We now turn to Neil Mehta with Goldman Sachs.

Good to see that inflection in the Delaware this quarter. I'd love for you guys to spend a little bit of time talking about the return of capital. And in the past, you have leaned towards the variable dividend. There's a noticeable shift towards the share buyback program. Why do you think that's the right decision? And how should we think about the magnitude of return on capital over the course of the year?

Yes. Thanks, Neil. As you know, a couple of quarters ago, we rolled out a slight change to our framework and leaned in on 70% of our free cash flow is going to go back to shareholders via our fixed dividend, share repurchases, and then the variable. And then also, we made a commitment to building some cash to the balance sheet to manage the maturities that I referenced in my opening comments. So that continues to be our game plan and our expectations. Specific to the share buyback, without question, with the underperformance we saw on a relative and absolute basis last year in the equity market for our shares, and based on all the work that we do internally, all the modeling work we do around intrinsic value, it's pretty clear to us that the best thing that we can be doing with that free cash flow is leaning in on the share buyback. And so that's what you've seen us do the last couple of quarters, and we would expect that to continue as we walk forward into 2024. This pace of, call it, $200 million to $275 million a quarter, currently feels about right. Obviously, as we work our way through this year and our capital spending will moderate as we talked about in our opening comments, I think there's even potential for a little incremental leaning on that as well. But we feel really good about the share repurchase program, the results that we've been delivering there, and would expect that pace to continue.

That's helpful. And then the follow-up is just on local gas prices. Obviously, they're under a lot of pressure as we wait for Matterhorn to come online in the Permian. So just any thoughts on timing of that pipeline? And as you look out, big picture over the next couple of years, how long before we need the next pipe, but do we have visibility into it?

Yes. You bet, Neil. This is Jeff again. Great question and certainly something we've been talking a lot about internally and externally. First of all, I'll just say Matterhorn, we expect it to come on at the end of the third quarter, to answer your question directly. I want to highlight that we haven't had any issues moving our molecules despite the volatility that you've seen in WAHA pricing and the kind of downward trajectory of pricing here over the last, call it, 1 month, 1.5 months. We feel like we're in a pretty good position. Matterhorn is obviously going to help that when we get to the back half of the third quarter. But just as a reminder, we move about two-thirds of our gas out of basin to the Gulf Coast via the firm transport that we have in place. And then another 15% of our Delaware gas is protected via the hedge program that we execute each quarter. So that's helping as well. That remaining gas that is exposed to WAHA, one thing to keep in mind is about 75% of that gas is first a month. So we don't see all the volatility that you are looking at on the screen as it relates to the day-to-day when maintenance issues happen and other challenges out in the basin. So we feel like we're protected pretty well from the bit of exposure that we do have and certainly expect that Matterhorn is going to help relieve some of that pressure when we get into the third quarter. As it relates to other projects, there's a handful of other projects that our teams are engaged in discussions with third-party pipeline providers. As it relates to timing, I can't give you a specific answer, but I do think within the next 6 to 12 months, we'll see another FID in a pipe. And certainly, as you know, Devon historically, we've got a track record of leaning in to help those projects get off the ground, whether it be volume commitments or in the case of Matterhorn, we actually made an equity investment as well. So we're certainly going to be supportive of those projects and, like most others in the industry, we think that you're going to need another pipeline here within another 18 to 24 months.

Our next question comes from Nitin Kumar with Mizuho.

Good to see the Delaware is back on track. I kind of want to peel the onion a little bit here on Slide 9. It sounds like, based on what Clay was saying, that you expected the productivity improvement as you went back into New Mexico, and it's really the drilling and completion efficiencies and infrastructure that's driving the improvement. But could you perhaps help us quantify what was the contribution of the two things? And how sustainable that is going forward?

Thank you for the question and for allowing us to clarify this. Rick and I addressed this in our prepared remarks, but there are three significant factors contributing to the outperformance. Firstly, approximately 60% of the outperformance was due to well productivity, which really was the primary driver. Secondly, we increased efficiency in how we brought new wells online, and a few extra days of operation here and there cumulatively made a difference. Finally, from a base performance perspective, we significantly exceeded historical performance in both midstream operations and well management, influenced by weather and operational factors. Thank you for giving me the chance to clarify this. We might not have been clear initially.

No. Great. I just wanted to make sure. And I guess my second question is for Rick. We've seen a lot of M&A in the industry. And I know that you've talked about the importance of scale in the new shale business. As you look at the remaining landscape, are you comfortable with your current portfolio? Or are there areas where you feel like you could optimize it further?

We feel very assured about our portfolio, which we believe is of top quality and spans multiple basins, giving us a significant advantage. While we always evaluate our opportunities, our fundamental stance remains strong. We maintain a high standard, recognize the strength of our portfolio, and the results speak for themselves. Our focus on sustainability is evident, and we have even included a slide in our presentation that compares our portfolio quality to that of many of our competitors. Ultimately, year after year, we aim to be at the top in capital efficiency and continue to provide free cash flow to our shareholders. Regarding the idea of consolidation, our strategy has been consistent for several years. We played a role in initiating much of the consolidation in the industry, which has been beneficial in developing our strong portfolio.

We now turn to Scott Gruber with Citi.

Just curious with the improved productivity, both on the surface and on the wells in the Permian. Do you feel like the production profile for the full year could be a bit smoother, a bit more stable in the second half?

Yes. Thanks for the question, Scott. As we have done in years past, we are front-loaded on capital about 55% in the front half of the year and 45% in the back, and that's really driven by that fourth frac crew. Obviously, that comes with more wells online in the front half of the year, more growth. And so think about it: when we're running those 4 frac crews, that we are consuming some of the pent-up DUCs. And then we're running 3 frac crews, our production is rolling over a bit, but we're also building a little bit of a DUC inventory. And so as I expect, and we've guided to first-quarter is in the bag. Second quarter, we've guided to a little bit of additional growth. Third and fourth, we'll see a little bit of a rollover on the back of lower completions activity and then building those DUCs; we'll be ready to get back to work with a fourth frac crew either late in the year or probably more likely early in '25.

Got it. And then in the prepared remarks, you mentioned the potential to see some additional D&C deflation. Are you starting to see more equipment from particularly the Haynesville migrate into Texas and into the Eagle Ford and the Permian and start to loosen the rig and the frac markets up?

Scott, we baked in about 5% deflation from '23 to '24. We've continued with that mindset. I think that feels like it's materializing pretty well. There's a potential as we continue to run at this rig rate that we could see a little bit more deflation. But what I would really caution you on specifically to our guidance and why we reiterated our capital range is that we're also seeing a little bit of an acceleration of opportunities, more efficient drilling, and more efficient completions, which you know can put a little bit of positive pressure on that near-year capital number. Now the good news, and I want to make sure we're all clear on this, both deflation and the efficiency gains are accretive to the bottom line of each of these drilling opportunities. So we are winning on both sides. I just want to reiterate that we are reiterating our capital range and still feel good about where we're at there.

Our next question comes from Neal Dingmann with Truist.

Just one for you, Clay. Looking at Slide 7 on that Delaware plan, it appears to be progressing well. I'm curious, when we examine that plan for 2025, how will the areas outlined in the 2025 plan differ from those in 2024?

Thank you for your question, Neal. We are returning to the proportions that we had before 2023 as we move into 2024. This aligns with the overall portfolio ratio we have between New Mexico and Texas, as well as the Delaware Basin compared to the rest of the company. You can think of 2024 as a return to a more typical state, as 2023 was somewhat of an anomaly. We decreased our focus from about 70% in New Mexico to approximately 60% in that region, which is reflected in the overall average well productivity. Our current shift back to 2024 represents a more steady state for what we anticipate in 2025 and beyond.

No. I would love to hear that. And then secondly, just quickly on Anadarko and Eagle Ford. I mean both are producing about the same. Again, when you think about maybe the exit or again, even '25 on either of those, should we think about those as remaining relatively flattish? Haven't heard you say too much on those. We wonder anything you might add for either one of those plays?

Yes, I would say roughly. We will continue to evaluate near-term opportunities there. We are excited about the depth of inventory and are discovering new items ahead of us that are not even reflected in our current inventory models. This keeps us enthusiastic. We are always assessing which projects should prioritize. This addresses both of your questions. Remember, the wells we are bringing online, particularly in the Delaware, are driving our performance. A couple of years ago, these wells did not perform nearly as well as we are seeing now. Therefore, our optimism about what is coming in the next few years across all our basins remains high, as we have many talented individuals working on excellent ideas to improve recoveries and enhance operational efficiency.

Our next question comes from Roger Read with Wells Fargo.

Congrats on the quarter here. I'd just like to come back a little bit on comments from the opening about potentially repaying debt and trying to think about the uses of cash in terms of does it make sense to pay down debt given your balance sheet is already strong? Is there another use of cash we should think about here in terms of either more back to shareholders or has been asked a little bit earlier, something on the acquisition front, like build a little cash in front of need?

Yes, Roger, this is Jeff. Again, we remain committed to the upcoming debt maturities that we have this year and next year. We continue to believe that in this business, with the volatility that we have, the wide swings that we can have in commodity prices from, frankly, day-to-day, week-to-week, certainly quarter-to-quarter. It's important for us to maintain that strength in our balance sheet and that stability. And frankly, it just provides us a lot of optionality to go do, whether it be incremental share repurchases or should we find the right opportunity, as Rick described on the acquisition front, that will be an option for us given the capacity that we'll have within the balance sheet. But at this point in time, we're going to continue to focus on building a little bit of cash on the balance sheet to handle those upcoming maturities, and then we'll see where things go from there.

Fair enough. The other question is about the efficiencies, particularly capital efficiencies and completion efficiencies that are on Slide 9. If you consider it in the context of the overall deflationary environment, how do you compare lower rig rates and lower frac costs to the improvements? Which do you believe is more important?

Between those two, I would probably prioritize completions since they represent a larger investment. However, I also want to emphasize the deflation we are witnessing in pipe. In 2023, steel costs were the highest category by far, but we have seen a significant decline in those costs recently. We hope to see further improvements, but we remain objective about overall well costs. We are confident in our current guidance. As I mentioned earlier, I am optimistic for some additional inflation, yet I recognize that the efficiency gains we have achieved lead me to maintain our capital guidance.

We now turn to Kevin MacCurdy with Pickering Energy Partners.

Congratulations on a good quarter. As a follow-up to the question on production trajectory, I know it's still early in 2024, but what kind of optionality does your ex rate give you for 2025? You were initially targeting flat oil this year, but better results are resulting in small growth. Is this new full-year guide kind of the new maintenance level heading forward?

Yes. I would say it's a little too early to talk 2025, but certainly, as I mentioned in a prior question, we model, we have good models. We have internal looks for '25, '26, and then we always reserve the right to get smarter. So I would expect our '25 internal expectations, which we haven't talked about publicly, to continue to migrate up as they do in prior years. But I don't think it materially moves our expectations of what we're doing now. In my mind, this is something that is kind of standard operating procedure on what we're doing. We always expect our D&C teams to move more efficiently. We're always expecting our production teams to be a little bit more operationally savvy and efficient. And then for the subsurface folks, building in that creative magic to extract just a little bit more of the resource and be a little bit smarter on how we do this overall. And I think that's the part I'm excited about and what I continue to see as we roll into '25.

Great. And as a follow-up, you guys have made a number of successful midstream investments over the years, including Matterhorn. What would be the catalyst for you to start to realize the value of those assets in any near-term monetization plans?

We'll always assess when we believe the timing is right, especially when midstream multiples differ significantly from our current position. We will align this with our strategy to ensure we continue delivering our commodity and maintain the influence we require. This opportunity will likely arise in time, and we will keep a close watch on it.

No, I think you said it well, Rick, which is it really is a function of the evolution of the lifecycle of the asset and where we are on that. And as Rick mentioned, we've tried to be opportunistic with those investments. Certainly, we want to support projects as needed, and where we can put some equity to work as well, we're not adverse to doing that. And as Rick mentioned, from a governance standpoint, there are some situations where we want to have a little bit more control, but usually, as those assets mature, that tends to dissipate, and that likely becomes a time where we'll look at the market dynamics and consider some sort of exit or monetization. But I feel good about where we sit today with the investments that we have in hand, and they've served us well as we're working to move our molecules.

Our next question comes from Charles Meade with Johnson Rice.

Clay, I know you have several questions this morning regarding the impressive quarter your team had. To what degree should we expect that performance to continue? I understand you might be hesitant to make a public commitment, and likely even hesitant internally. However, I want to explore a different angle. Specifically, how much interaction is there between the performance of the wells and the easing of infrastructure constraints? My understanding is that there are many new well pads in the Delaware that could be producing at higher levels if not for these constraints. Is it the easing infrastructure that has allowed you to achieve the rates you've mentioned for those three Delaware pads?

That's a great question, and I’d like to address it. We always appreciate discussing operations as it aligns with our objectives. If we refer back to Slide 9, we touch on well productivity and completion efficiencies. In both Rick's and my prepared statements, we mentioned three key components contributing to our performance. The outperformance from our base operations was crucial. Overall, about 60% of this outperformance stemmed from well productivity, around 20% was due to bringing projects online sooner, and another 20% related to uptime improvements linked to fewer constraints compared to 2023 and historical data. However, we did have some constraints, and there are pros and cons to operating in the hottest basin globally, which is the Permian, particularly in the Delaware. Jeff has received inquiries about the midstream build-out, and we are closely monitoring that. It's not just about gas; we also consider water, oil build-out, processing, and electrification, all of which we must manage in a multifaceted manner to tap into this highly productive resource. A specific challenge in the Delaware involves the number of landing zones, which are constantly evolving. We pointed out that the Wolfcamp B is likely to become more significant moving forward. As we incorporate this, we must also consider the changes in infrastructure and its requirements. Regarding your earlier question about whether our wells are held back due to infrastructure constraints, the answer is yes; there's always something there. We won’t push volumes into a system that is not equipped to handle them, and we strive to minimize disposal fees for gas. We're also very mindful of our flaring rates, which we've significantly reduced over the past few years, and we aim to maintain those improvements. There's a lot happening, and I’m very pleased with our team’s performance and grateful to represent the team during such a successful quarter.

And then just one quick clarification for a follow-up. When you say 60% well performance, is that new wells brought online, the performance of new wells? Or is that the new wells plus the base?

I am attributing 60% to the new wells; the 20% I mentioned regarding the base relates to the existing wells and other base activities that are performing better than what we had anticipated in our forecast.

We now turn to Scott Hanold with RBC.

Clay, a lot of talk on the Permian, but it sounds like the Bakken really pivoted quite a bit this quarter too. And I'd be interested to hear any kind of color on the high grading and what we can expect from that through the course of the rest of this year in terms of like when the next completions are coming in? And is it very similarly targeted in the same areas in spacing?

Scott, we've loved the Williston Basin for a long time. In '23, we probably pushed a little harder than the infrastructure and the well productivity was ready for. And so we've slowed that down. And again, just a great move to improve that capital efficiency. We have the benefit of a franchise asset in the Delaware Basin that gives us that latitude to not over-accelerate into wells or infrastructure that's not quite ready. And so what you see on the Bull Moose and the North John Elk are some core of the basin opportunities that we needed to wait until all the stars aligned to be able to bring online. We've actually got another rig back out there drilling some more core basin wells, about 10 of them that will come on either very late in the year or first of next year. Again, it's all baked into the plan. But that's probably the consistency, the approach that we're going to take rather than being forced into consistently running a rig and probably pushing some wells in that weren't quite ready for prime time. We're going to take the opportunity to drill what's available, release that rig, bring it back in when the next opportunity presents, and you'll see incredible results from it. Again, the Williston Basin continues to prove the quality of that asset; the oil cut, as Rick pointed out, the incredible amount of cash flow that comes from that basin is very valuable to our bottom line and the core of what we believe is the right business approach for our organization.

So just to clarify on that then, should we expect quarter-to-quarter some gyrations in production, but like year-on-year, should it be relatively flat in terms of production?

Yes, I would say roughly. That's correct. But certainly, as we're bringing on a pad and then it's absent for a while, you will have some peaks and valleys in the Williston. I hope that doesn't disrupt the visuals, it should kind of flow into everything else we're doing. But yes, as we are a little bit more selective, again, I believe it's the right approach in this asset, you will have some growth some quarters and some rollover in others.

And then turning back to the Permian, the Wolfcamp B. How extensive is that in terms of what you think is upside to identify the inventory beyond that 50 locations? And are there other zones that you're looking at that would add to the focus locations as well?

It's interesting to note that we discussed the Wolfcamp B a couple of quarters ago, highlighting its success in a different part of the basin. The B extends across the Delaware Basin, and this area, positioned more to the northeast in the Thistle region, is one we haven't really explored yet. It's less mature compared to other areas. So far, three wells have produced from the B, with the first two yielding moderate results, which set our expectations at a cautious level. However, as we focus on developing these regions, we decided to implement a modern completion approach to see how it performs. The outcomes have significantly exceeded our expectations. With our current strategy, we are excited about the differential uplift. The 50 wells mentioned are exclusively located in our Thistle area, and we have additional B wells planned in other parts of the basin, which are in addition to the 50. We will continue to seek out additional opportunities. We emphasized Thistle because it is not included in our inventory, representing upside potential that is now competitive for capital investment.

Our final question comes from Matthew Portillo with TPH.

I have a question for Clay to begin. Regarding the Anadarko, it’s encouraging to see a reduction in drill bit capital. It seems like we're reducing to two rigs due to the current commodity price environment. I was wondering if you have any updated thoughts for the year? Also, looking ahead to a more favorable environment beyond 2024, what opportunities do you see to potentially accelerate this asset in a better gas price scenario?

Thank you for your question. We have a strong partnership with Dow, and we want to ensure we are good partners by coordinating closely with them. I don't want to jump ahead, but I can say that we have been very aligned and appreciate both the value and nature of this partnership. If the right opportunity arises, I believe we would be in agreement on accelerating efforts. However, the current forward gas curve remains quite challenging. Given our balanced portfolio, especially the performance of the Delaware Basin, we feel there’s no need to funnel money into an area that isn't fully recognized. That said, with the support from Dow and the hard work of our midstream team to maximize value from this commodity, we are actually seeing decent returns. While we aren't focusing on Wolfcamp A wells, we still see value creation. We will maintain 2 rigs in the Dow joint venture area, look for additional opportunities, and even consider extending the Dow joint venture beyond our current scope. It's a great partnership, and we enjoy working with that team, as we both benefit from it.

Yes, we continue to have interest in gaining exposure to water in relation to both oil and gas, particularly in the LNG sector. We're actively engaging with various parties, including Delfin, and that effort is progressing. While there are no new updates beyond what we've previously shared, we are committed to accessing the LNG market as it pertains to our gas production. Additionally, we have a substantial stake in Delaware gas, which connects to the Gulf Coast, with some flows into the Katy market. We have extra capacity that allows us to move from Katy to the Louisiana hub where there is significant LNG demand now and in the future. We believe we are well-positioned to capitalize on that additional demand while maintaining discussions with multiple stakeholders.

All right. Well, I appreciate everyone's interest in Devon today. It looks like we've made it through the queue of questions. If anything else comes up later on the day, please feel free to reach out to the Investor Relations team at any time. Thank you, and have a good day.

Ladies and gentlemen, today's call has now concluded. We'd like to thank you for your participation. You may now disconnect your lines.