Devon Energy Corporation (NYSE:DVN) Q2 2024 Earnings Call Transcript

Devon Energy Corporation (NYSE:DVN) Q2 2024 Earnings Call Transcript August 7, 2024

Operator: Welcome to Devon Energy’s Second Quarter 2024 Conference Call. At this time, all participants are in listen-only mode. This call is being recorded. I’d now like to turn the call over to Mrs. Rosy Zuklic, Vice President of Investor Relations. You may begin.

Rosy Zuklic: Good morning, and thank you for joining us on the call today. Last night, we issued Devon’s second 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. Joining me on the call today are Rick Muncrief, President and CEO; Clay Gaspar, Chief Operating Officer; Jeff Ritenour, Chief Financial Officer; and David Harris, Chief Corporate Development Officer. As a reminder, this conference call will include forward-looking statements as defined under U.S. securities laws. These statements involve risks and uncertainties that may cause actual results to differ materially from our forecast. Please refer to the cautionary language and risk factors provided in our SEC filings and earnings materials. With that, I’ll turn the call over to Rick.

Rick Muncrief: Thank you, Rosy. It’s a pleasure to be here today. We appreciate everyone taking the time to join us. By all measures, the second quarter was another excellent performance for Devon as our business continued to strengthen and build momentum. Our quarterly results were driven by our Delaware-focused operating plan, which led to record oil production, expanding EBITDA, and another round of strong cash returns to shareholders. Additionally, our effective cost management resulted in capital coming in well below expectations. We also took important steps to strengthen the quality and depth of our asset portfolio with the accretive acquisition of Grayson Mill. All in all, it was another quarter of systematic execution that advanced both the financial and operational tenets of our strategic plan.

Now let’s begin on Slide 7 by covering a few of our second quarter highlights and operating trends in greater detail. Beginning with production, we once again surpassed guidance expectations by a wide margin with our per-share volumes growing at a healthy clip of 9% year-over-year. This attractive per-share growth rate was driven by oil production reaching a record-high for us of 335,000 barrels of oil per day, coupled with the benefits of our sustained stock repurchase efforts throughout the year. A key driver of this record-setting oil result was a superb performance we delivered in the Delaware Basin. By leveraging the benefits of a temporary fourth frac crew, we were able to bring online 62 new Delaware Basin wells in the quarter. Well productivity from this batch of wells was once again outstanding with per-well recoveries on track to achieve a greater than 10% uplift compared to last year’s program.

Looking beyond the Delaware, re-development success in the Eagle Ford, appraisal progress in the Powder River Basin, and a strong base production from our legacy Williston position also contributed to our volume beat this quarter. The team also continued to do a great job across the portfolio of controlling cost with capital and operating costs coming in well below guidance for the quarter. The strong cost performance was driven by effective supply-chain management and improving cycle times that resulted in multiple drilling and completion records across our asset portfolio. Importantly, these efficiencies not only accrue to us in the form of lower well costs, but also save us valuable time and further bolstering our project-level returns. Now with this operational performance, we’re pleased to raise our production guidance for the second time this year.

The improved outlook is driven entirely by our legacy portfolio. We now expect to produce more than 680,000 BOE per day in 2024, which represents a 5% increase compared to our initial budget expectations heading into the year. In addition, our outlook was further strengthened by the Grayson Mill acquisition in Williston Basin. These assets are an excellent addition to our portfolio, fitting perfectly within our broader strategic framework to accumulate resource and grow oil-weighted production in the best parts of the top U.S. shale plays. Upon completion of the transaction, Devon will be one of the largest oil producers in the U.S. with average daily rates estimated at around 375,000 barrels of oil per day. This transaction nearly triples our production and expands our inventory in the Williston Basin.

At the current pace of development, we have about 10 years of Bakken project inventory. This vast improvement in operating scale places Devon in a great position to harvest high-margin production from this prolific oilfield for many years to come. It’s also important to note that our Geoscience team is really encouraged about having an additional 300,000 net acre position to evaluate for future development opportunities over the next several decades. We see significant financial value created from this acquisition. We expect sustainable accretion to earnings and free cash flow. Given the strength of this transaction, we’ve expanded our share repurchase program by 67% to $5 billion. This increased authorization provides us ample capacity to continue to opportunistically repurchase our stock and bolster our per-share growth trajectory for the next few years.

We expect free cash flow from this acquisition to be additive to our dividend payout in 2025 and beyond. And lastly, as I look ahead, the outlook for Devon in 2025 is shaping up to be exceptionally strong. With the Grayson acquisition, we are now positioned to deliver healthy double-digit growth in both oil and free cash flow next year. Our legacy portfolio in key U.S. basins will provide a solid foundation for us to continue the momentum we’ve demonstrated so far this year. We will provide detailed guidance in the coming months as our planning process matures, but I’m confident that Devon will have one of the more advantaged outlooks in 2025 of any E&P company out there. And with that, I’ll now turn the call over to Clay. Clay?

Clay Gaspar: Thank you, Rick, and good morning, everyone. Our team delivered another round of impressive operating results in the second quarter, beating our guide and The Street and raising full-year expectations as illustrated on Slide 12. I want to congratulate the entire organization along with our service company partners for not only achieving these outstanding production and financial results, but also their commitment to safety and our environmental standards. Let’s start with Slide 8 with our franchise asset, the Delaware Basin, which drove our strong outperformance. In the second quarter, this asset achieved record-high production reaching 461,000 BOE per day, which represents a 5% growth rate compared to the previous quarter.

In a bit, I’ll talk more about the operational improvements that we are achieving on the drilling and completions front. But first, I want to clarify that this production beat is almost entirely driven by our outperformance of the new wells and the base production. The impact of drilling and completing a bit faster adds considerable value to each well’s project economics, but this timing doesn’t typically add much to an individual quarter’s production. As Rick mentioned earlier, we brought online more than 60 wells during the quarter. These wells were diversified across our asset footprint, primarily targeting the stacked pay within the Wolfcamp formation. In aggregate, these projects achieved average 30-day rates of more than 2,800 BOE per day with recoveries projected to exceed $1.3 million BOE per well.

With improving well costs and impressive performance, I’m confident that this batch of high-impact projects is delivering some of the best returns in the entire U.S. Given the operational momentum we’ve achieved so far this year, it’s no surprise that the Delaware is the driving force behind the company’s improved production outlook. As I mentioned earlier, the key factors for this improvement is the excellent well productivity from this year’s IDs as well as impressive base production performance. As shown on the left-hand side of Slide 9, we are firmly on track to improve our performance by more than 10% year-over-year. An important driver of this improvement is the easing of infrastructure constraints in New Mexico, which has enabled us to increase capital investments in areas that we have the most extensive runway of high-quality inventory.

Additionally, the continued optimization of our well design and the successful co-development of intervals in the Wolfcamp A and B formations have been highly impactful. This impressive start for the year has positioned us among the top performers in the basin, as illustrated on the right side of Slide 9, our Delaware wells have consistently ranked in the top quartile of our industry peers. This superior well productivity reflects not only the quality of our resource base, but also the team’s keen focus on operational excellence and performance optimization. Turning to Slide 10, we illustrate the impressive operating efficiencies we continue to achieve in the Delaware. From a drilling perspective, our team has achieved a 12% efficiency gain year-over-year and it’s continually exploring ways to optimize our rig fleet and the associated drilling services.

Additionally, the team is innovating across the entire drilling system from the bit to the crown block. We are working on technological applications in the realm of downhole sensing to improve well placement, casing design innovations, and overall flat time reduction, including tripping and connection practices and offline operations. On the completion front, we have delivered a 6% improvement year-to-date on top of the 10% improvement from last year. This step-change was significantly influenced by incorporating fit-for-purpose simul-frac operations across our development programs. Further, our continued application of leading-edge reservoir and frac modeling has allowed us to refine our stimulation designs, improving well cost and more importantly, well productivity.

In addition, seemingly small items like sand, water, and location logistics are critical areas of focus that allow us to achieve both performance and safety improvements. It is important to note that these operational improvements are not in conflict with our strong safety focus. In fact, our safety metrics have also made significant improvements year-over-year. These operational improvements certainly create value to the bottom line for this year’s drilling campaign, but more importantly, we will continue to apply these learnings and our continuous improvement culture to the thousands of remaining wells in our Delaware Basin inventory as depicted on Slide 11. Now let’s turn to our other key assets in the Eagle Ford, Anadarko Basin, and Powder River Basins.

Collectively, these assets delivered a 12% production growth compared to the previous quarter. In the Eagle Ford, production growth was driven by strong redevelopment results in DeWitt County, where average 30-day rates from this 15-well program consistently exceeds $3,000 BOE per day per well. In the Anadarko, our capital program driven by our joint venture with Dow delivered both solid returns and double-digit production growth in the quarter. Looking ahead, we expect the benefit of these carried enhanced returns with Dow will support Anadarko activity through most of next year. Furthermore, we’re evaluating opportunities to expand this mutually beneficial partnership. In the Powder River, our team is making significant strides in assessing the Niobrara development in Converse County.

Over the last 18 months, the team’s focus on subsurface technical applications have resulted in higher productivity and has continued to bolster our confidence in this asset. The next step in Powder is to refine development spacing across a very large play fairway and continue to reduce well costs as we move towards more development-oriented activities. We have identified material improvements that are shaping up to be needle movers for this important future development for Devon. Moving to the Williston Basin, as Rick touched on earlier, the Grayson Mill acquisition is transformative to our position in the basin. We’ll be adding incremental leasehold over 300,000 net acres with 500 undrilled Bakken and Three Forks locations. Upon completion of the transaction, we expect to maintain an oil-weighted production of around 100,000 BOE per day.

We expect to manage these assets to allow for a more substantial long-term production profile. To maintain this level, we anticipate an incremental capital investment of around $600 million in the upcoming year. Looking ahead, once we formalize our 2025 capital budget, we plan to provide an update on our optimized development strategy for this asset, which will include a combination of two and three-mile laterals supplemented by tactical re-fracs that will enhance our base production. We expect to operate a consistent three-rig program across our entire Williston Basin acreage position, allowing us to benefit from operational efficiencies in the field. In summary, I look forward to a successful Grayson Mill integration and continue to deliver industry-leading results.

With that, I’ll turn the call over to Jeff for financial review. Jeff?

Jeff Ritenour: Thanks, Clay. Beginning with the second quarter financial performance, Devon’s core earnings significantly expanded year-over-year and totaled $885 million or $1.41 per share. This level of earnings translated into operating cash flow of $1.5 billion, a 9% increase year-over-year. Operating cash-flow funded all capital requirements and generated $587 million of free-cash flow for the quarter. We ended the period with $1.2 billion of cash on the balance sheet and a low net-debt to EBITDA ratio of 0.6 times. Consistent with our disciplined cash return framework, we returned approximately 70% of excess free-cash flow to shareholders through a combination of buybacks and dividends. Given the compelling valuation of our equity, cash returns are skewed towards share repurchases over the variable dividend.

We bought back 5.2 million shares for $256 million during the quarter. In addition to our share repurchase program, our Board declared a fixed-plus-variable dividend payout of $0.44 per share. This distribution will be paid at the end of September. Overall, we believe the flexibility of our cash return strategy provides us the opportunity to return meaningful and appropriate amounts of cash to shareholders across a variety of market conditions through the cycle. With the recent market volatility and pullback in our equity price, we’ll continue to bias cash returns to share repurchases relative to the variable dividend. Looking ahead, we expect another strong performance in the third quarter with oil production forecasted to average 322,000 barrels per day.

On the capital front, we anticipate spending in the third quarter to remain essentially flat versus the prior period at around $900 million before moving lower in the fourth quarter. For the full year, our production forecast continues to trend higher while adhering to our original capital investment plan, albeit in the upper half of the guidance range with continued operational efficiencies pulling forward activity. Turning to our balance sheet, we’ll fund the Grayson Mill acquisition with $3.25 billion of cash and $1.75 billion of stock. For the cash portion, we expect to use a combination of cash-on-hand, shorter-duration term loans, and long-term notes. Moving forward, we’ll look to build upon our financial strength and we’ll initiate a $2.5 billion debt reduction program.

We expect to complete this debt reduction plan within the next few years and have flexibility with upcoming maturities and the anticipated term loan issuance. With that, I’ll turn the call back over to Rick for some closing comments.

Rick Muncrief: Thank you, Jeff. To wrap up our prepared remarks, I want to reinforce a few messages. Number one, we delivered an outstanding second quarter marked by record oil production underpinned by excellent well productivity from our franchise asset, the Delaware Basin. Number two, effective cost management resulted in capital and operating expenses coming in below guidance due to efficient supply-chain management and improved cycle times across the portfolio. Number three, the strong performance led us to raise our 2024 production guidance for the second consecutive quarter, now projecting to reach over 680,000 BOE per day, an impressive 5% increase from original expectations. Number four, this improved outlook is driving increased free cash flow, translating to higher cash returns for our shareholders.

Given our equities value proposition, we believe prioritizing share repurchases is the best course of action. Number five, looking ahead, Devon is well-positioned as we go into 2025, anticipating strong double-digit growth in both oil and free cash flow supported by our legacy portfolio and the Grayson acquisition. And with that, I’ll now turn the call back over to Rosy for Q&A.

A – Rosy Zuklic: Thank you, Rick. Emily, we will now open the call to Q&A. I ask that all of you asking questions to please limit yourself to one question and one follow-up. And with that, we will take our first question.

Q&A Session

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

Arun Jayaram: Yes, good morning. My first question is just how to think about activity in the second half of the year on a Devon standalone basis. Your original TIL guide was $375 million to $430 million and the company completed 216 TILs in the first half, which would kind of if you annualize that, it would place you towards the upper end of that range, but obviously you’ve suspended the fourth-frac crew. So just trying to think about how activity trends could play out in the second half of the year, particularly in the Delaware.

Clay Gaspar: Hi, thanks for the question, Arun. This is Clay. Yes, so you nailed it. The first half of the year was benefited by the fourth frac crew. Now interestingly, we moved that frac crew in and out a little quicker than the original plan. So you saw some second quarter capital benefit from that. But I would say to the heart of your question, it’s a little bit front-end weighted, but relatively flat over the course of the year. And so we’ll benefit from that fourth frac crew in the front half. We get a little bit of benefit of depressed capital in the second half that should balance things out nicely.

Arun Jayaram: And Clay, just a quick follow-up on that is the working interest has been moving around a little bit in the Delaware. Any thoughts on the projects and what the working interest will look like in the second half? And I have one follow-up.

Clay Gaspar: Sure. It definitely affects the capital. But the – we try and manage that through the year. I can tell you, it’s hard to manage that in addition to all the other important levers. And so as we march through the year, we could actually see a little bit of a step-up in the first quarter. Well, first quarter, we had a little bit of a step up. So second half we’ll have a little bit lighter working interest.

Arun Jayaram: Okay. And just a follow-up, I know you’re not ready to put 2025 outlook out there, but the capital program on a standalone basis has been running around $900 million or so the last four, five quarters. So if we just annualize that, you get to 36 and you mentioned $600 million of incremental spending from Grayson Mill. Is $4.2 billion a decent placeholder as we sit here today.

Clay Gaspar: Yes, obviously, too early to telegraph too much on 2025, but I get that it’s part of your job to ask. So what I can tell you is directionally, that’s not too far off. What happens between now and the announcement of our budgeting process is we have a strategy session with the Board in the next month. We’ll talk about all kind of different scenarios and really challenge ourselves. And then we refine it. We run internal sensitivities. Then, of course, we need to close on Grayson. We hope that still lines up in the end of the third quarter. And then once we get that out, we’ll be able to talk a little bit more holistically about where it fits in the overall project. So more to come on that, but I would say from the start, directionally, you’re not too far off.

Arun Jayaram: Great. Thanks a lot, Clay.

Clay Gaspar: Appreciate it.

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

Neil Mehta: Yes, good morning, Rick and team. Just a follow-up on

Rick Muncrief: Good morning, Neil.

Neil Mehta: Arun’s question. I think – morning, sir. It’s more of a philosophical question that we’ve been asked by investors, which is operationally, you guys continue to do very well and get the momentum back. But you were probably at this decision point, you could have throttled back the capital and hit the volume or you could have kept the capital the same and beat the volume guide. Can you walk us through the decision tree of – especially taking into account the macro, how you came to the decision to maintain the CapEx, but to focus more on the volume side? And I would imagine that’s free-cash-flow neutral decision, but curious on the perspective.

Rick Muncrief: Hi, Neil, it’s Rick. I’ll start with that and hand it off to Clay. You know the reality is, I’ve seen time-and-time again over the last 40 years when you – things are looking good only to have some kind of a downstream constraint to surprise you, whether, whatever it may be. So what we did is we decided volumes were looking really, really, really good. We stuck with our game plan, exceeded the expectations and – but we did have some discussion around that and – but we stuck with a plan, you saw the performance. I thought it was important also for us to show once again, when we talk about 10% uplift, we talked about that for the Delaware position over 2023, what kind of performance we expected and we wanted to deliver that. And I think the team did a phenomenal job doing that. So Clay, why don’t you provide a little more color, a little more detail?

Clay Gaspar: Yes, Neil, great question. And I think it’s pretty fundamental. As we think about do we absorb those accelerations and kind of continue to provide to the upside on production or do we trim back? I would tell you there’s a mixed bag. We are always you know way below the radar doing a lot of things. I mentioned the fourth frac crew. As that frac crew was able to develop its amount of work quicker, we’re able to release that earlier. We’ve high-graded a couple of rigs. We’ve actually gapped a couple of rigs during the year. We continue to evaluate for the balance of the year. And certainly, as we look into 2025, what is this increased productivity per rig, per frac crew really mean? I think you pointed to the right thing.

We’re thinking more about capital. We’re thinking about net wells, maybe more importantly, net footage that we’re delivering and how does that translate into the best-value opportunity? We’ll still continue to hold to our 0% to 5%. I think we’ll stay well inside that range, but it’s – we are on the winning side of this, right? We’ve got improved cost structure accreting to better per well economics. The challenge is you drag a little bit more capital in and that still remains to be seen how do we manage that? So far so good. We’re staying inside of our capital guide range. Feel good about that. More information to come on the balance of the year and how we shape things up for 2025.

Neil Mehta: Yes, that’s really helpful. And then just the follow-up is on your perspective on the M&A market. Obviously, Grayson was an important step forward as building out your Bakken business and getting inventory to where you want to be. But do you see incremental opportunities as we look forward over the next year? Your just latest thoughts on the A&D market and how Devon fits into it.

Rick Muncrief: Hi, Neil, you know our mantra has been and always will be that we will always have our eyes open, but the reality is that we have once again a high bar and we’re really laser-focused on getting Grayson Mill closed, getting it integrated, executing once it is integrated in the company. And so we’ll see how that all plays out. But I can tell you, we’re all excited about this company we’ve bought and I think it’s going to be a great addition and shareholders are going to truly benefit, but we’ll maintain that discipline and high bar.

Neil Mehta: Thanks, Rick. Thanks, Clay.

Rick Muncrief: Thank you.

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

Neal Dingmann: Good morning, guys. Really nice results. Rick, my first question is likely for you or Jeff. Just was wondering, it’s on capital allocation specifically. You don’t think any different today about the buybacks versus the variable dividend given still how cheap your stock is and how volatile the commodity market continues to be?

Rick Muncrief: Absolutely, Neal. It’s something we talk about quite a bit. I’m going to have – I’m going to have Jeff weigh in on this. But certainly, the way our equity is priced, we just think it’s a great opportunity right now to be leaning in on the buyback. But Jeff, why don’t you?

Jeff Ritenour: Yes, you bet, Neal. Appreciate the question. And I know you’re familiar with our financial framework. We’re – as Rick highlighted in his opening remarks and just there in his response to your question, we think the – our bias is going to continue to be to lean in on the share repo. Our approach to that has been to be consistent quarter-after-quarter. We think somewhere in that $250 million kind of spend per quarter makes the most sense. The variable dividend falls out of that, right, as a function of the free cash flow we generate in each period. We take some back to the balance sheet. We make sure we’re paying our fixed dividend and growing that over time. And then the balance is going to be dedicated to the share repurchase program.

We’re excited about Grayson Mill and getting that closed because that’s going to add some incremental free-cash flow to our company, which is going to allow us to think about even expanding upon that absolute amount of share repurchases that we do on a quarterly basis. So without question, the bias is going to continue to be towards the share repo given what we’re seeing in the market right now.

Neal Dingmann: Yes, love to hear that. And then my second question on the Anadarko and PRB plays. Specifically, maybe for Clay, just Clay your thoughts or expectations for future activities two plays. It sounds like based on your prepared remarks, you certainly believe Anadarko has returns that more than justify the incremental capital. I’m just wondering how you sort of see these two plays compete against the Delaware and the soon-to-be-increased Bakken plays?

Clay Gaspar: Thanks for the question, Neal. Yes, I think both of them are complementary assets. In the case of the Anadarko Basin, having that partnership with Dow really helps promote those returns to compete in our portfolio. On the Powder River side, we think it’s think it’s an important future piece of our business. And so we’re investing in it kind of prospectively to really understand what’s the right combination, what’s the right approach, and really unlocking that very material, very oily potential for our future. So you’re not going to – never going to – not going to see these kind of dominate our capital call, but they certainly have a place in the portfolio and continue to allow us to look for our future, build for our future. Thanks, Neal.

Neal Dingmann: Well said. Thanks, Clay.

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

Roger Read: Yes, thank you. Good morning. Let me kind of pivot off your comment about share repurchases and just for the record, we’re all in favor of that. But you’ve been acquisitive. If you were to do something you know, larger acquisition-wise, obviously it starts to look at probably equity as a way to balance it. Just wondering what sort of metrics you would want to see in a transaction in order – a large transaction that would make you think about using the equity versus share repos. Like what are we – what should we think about as the key points there?

Rick Muncrief: Hi, Roger, it’s a great question. In our mind, the share repurchases, that share repo program, that’s kind of our base case. That’s what we know that we’re going to be doing. And as far as the transactions, that’s – you can’t always predict how that will play out for a number of factors as you can understand. But I think that I’m going to turn it over to Jeff, let him talk about some of the metrics, but certainly, our track record has been that we absolutely have to have that accretion to make it – make us a stronger company with the acquisition than without.

Jeff Ritenour: Yes, you bet. Roger, appreciate the question. And I’ll echo much of what Rick just said, which is that you all are familiar with our financial framework and we’ve been, I think, pretty transparent as it relates to our thoughts around M&A and what’s required for us to go out and capture incremental assets or think about merging with other companies, right? It’s very much driven by that free cash flow accretion that we’re looking for in any transaction. You’re always going to hear me say that the balance sheet is a priority. We’re going to be very thoughtful about any transaction, what we do, what the impact that that has on our investment-grade credit rating, and what that looks like into the future. So those are going to be a few of the priorities.

As it relates to whether or not we use equity in a transaction, that’s very dependent upon the specific opportunity that we have in front of us, right? Our bias is always to buy back our shares and not issue shares wherever we can. But depending upon the specific situation, and the transaction that we’re looking at what the seller is interested in, those are all different things that we’ll think about, as it relates to the capital structure and ultimately, how we finance that deal. But without question, our bias is to buy back our shares, given the current environment and the opportunity set we have in front of us in our base portfolio.

Roger Read: No, that sounds great. And then, I was wondering if I could follow-up on the comment. I believe you made it about the Bakken operations. The refracs, we’re hearing a lot more about that terms of the Eagle Ford shale, but I was just curious kind of what you have on tap in either the Bakken or the Eagle Ford. And then, if you could like what portion of CapEx – percentage of CapEx is directed that way?

Clay Gaspar: Yes, Roger, this is Clay. I appreciate the question. We are pretty excited about what we’re seeing specifically in South Texas around refracs. We have more experience and, frankly, more running room there. We have quietly posted some really nice numbers really kind of derisk that potential from how we approach these, we screen the wells to begin with the operational pieces of how do we clean out wellbore prepare them for the stimulation and then ultimately, what’s the right stimulation. When you run all of that through, it’s a pretty compelling return and it’s all upside to existing portfolio. We’ve also tried this in a few other areas. We’ve had okay results in the Anadarko Basin. We’ve had okay results in the Williston Basin.

Then you flip to the Grayson Mill. And the Grayson Mill guys have done a fantastic job on some of these refracs. This is one area that we talk about synergies, how can we learn from what they’ve done specifically in the in the Williston, apply that to even more of what we already have the legacy assets. But we see it as part of ongoing business really, I think, more of a supplement to the base production. So, we’re probably not going to be highlighting this as the big capital call on where we spend a significant portion of our overall capital dollars. But think of it as more supplemental. And we try and bring out more and more of the resource out of these incredible basins, I think this will be a very important tool in our portfolio.

Roger Read: Great. Thank you.

Clay Gaspar: Thanks.

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

Scott Gruber: Yes, good morning.

Rick Muncrief: Good morning, Scott.

Scott Gruber: Hi, guys. Good morning. Your operated well spud have been running ahead of tie-ins in the first half. You mentioned incorporating some gaps in the rig schedules. But just given the efficiency gave you guys are achieving on the rig side, you plan to drop any rigs on a more permanent basis? Or do you want to build some DUCs into 2025. How are you thinking about the size of your contracted rig fleet in the second half?

Clay Gaspar: Scott, we – I like the way you started with thinking about well counts from spuds, from initial deliveries and really thinking about the cadence of that as an earlier question came up, the net definitely plays into effect when you’re talking about capital but also production rolls into that. I think the rig count really is kind of a byproduct of the great work that the teams are doing, and our service company partners and making that equipment more, more efficient. So I would set the actual rig count aside a little bit. And again, we do things when we high-grade rigs, sometimes there’s an opportunity to overlap. Sometimes there’s an opportunity to gap those rigs a little bit. Again, we are less focused on the day-to-day rig count and more focused, on how do we maintain that expectation, and always look to improve from a productivity, and capital efficiency standpoint.

Scott Gruber: Got it. And then just shifting to the gas side, Matterhorn will be starting up here shortly. How do you guys see that you guys see that impacting the margin? Do risk the oversupply of at Waha gets, transferred down to Houston ship? Do you see a need to take out some more basis protection down at Houston ship? How are you thinking about the impact on the market?

Jeff Ritenour: Yes, Scott, this is Jeff. I appreciate the question. Yes, we’re – first of all, let me say we’re excited to get Matterhorn online, and I think it’s going to be a positive, obviously, not just for Devon specifically, but the broader sector as we move more of those molecules away from the Waha Hub. You’ve also heard about Blackcomb coming on in the 2026 timeframe. Again, we’re excited to be part of that project. And again, further the movement to get the molecules away from Waha. Specifically to Matterhorn from our standpoint, it absolutely is going to move molecules over the Gulf Coast. We’re hopeful to take advantage of the LNG pricing improvement that we’ll see over time as those projects get built out. But you’re right, there’s absolutely a risk of some of that backup of molecules being transferred from Waha over to Katy.

And that’s why we’ve also taken advantage of some other opportunities to move the molecules further away from Katy into Louisiana and beyond. And so, the marketing team has done a really great job, of kind of thinking about the entire value chain, and how we move these molecules, to where we can get the highest realized price. Because at the end of the day, that’s what we’re trying to accomplish. So, we feel really good with the commitments that we’ve made. And our ability to move the molecules around not just over to the Gulf Coast, but outside of the Gulf Coast, if you think about Oklahoma Gas is another example, we have ability to move that gas to the Southeast markets where in the second quarter, we were able to capture our premium to Henry Hub.

So a lot of great work done by the marketing team, and think we’re well set up for the future.

Scott Gruber: Appreciate the color. Thank you.

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

Kalei Akamine: Yes. Hi. Good morning guys. Rick, Clay and Jeff. I want to ask on the Blackcomb pipeline, and I’m going to tie it into some feedback that we get on Devon, which is that the inventory isn’t sufficiently differentiated from peers yet you guys are one of the few companies that continue to sign a new pipe, Matterhorn and now Blackcomb. And that’s a real commitment. So my question is, as you think about meeting that obligation in second half 2026, what’s the base case to fill – to fill that pipeline. Is it with incremental gas? And if so, what does that infer about your Permian oil growth over this period?

Jeff Ritenour: Yeah. This is Jeff again. I’ll start and give you a little bit of color on how we think about these – making these firm commitments, and then Clay can speak further about our depth of inventory in the Delaware. But I like the way you started the question, which is it begs the question, why are we making these pretty significant commitments, if we’re worried about our Delaware inventory position. And so that probably answers the question. But without a doubt, we believe we’re going to continue to see gas production grow, obviously, in the Delaware Basin as we continue to pursue our oil dedicated and oil commitments – excuse me, our commitment to drilling more and more oil projects in the Delaware Basin. We’re going to continue to see that gas grow.

And so that’s why we think it’s so important to help support these projects like Matterhorn and Blackcomb, by making these volume commitments. So without question, we feel like we’re going to have the ability to make our commitment on both Matterhorn and Blackcomb. And I’ll flip it over to Clay, and he could talk a little bit more about the inventory, and the position that we have there.

Clay Gaspar: Yes. Thanks for the question. I’ll take the inventory piece and happy to talk about it. This is something I remember 18 months ago, 12 months ago, when folks are worried that we are falling off the cliff and running out of inventory. And here we are producing some of the best most productive wells that, we’ve ever produced and posting some fantastic numbers. So I think our runway looks incredibly strong. I’ll refer you to Slide 11, where we have third-party data, looking at the inventory, not just ourselves, but of our peer companies. And again, our team does an amazing job of trying to unlock that white part of the bar on those curves, which is the upside potential. And as we drive down those costs and improve the efficiencies, slightly improve on those recovery factors, eke out a little bit more of those resources that white spot becomes more of a gray, and then it becomes really part of that in-hand inventory.

And so, we literally have thousands of wells ahead of us. We feel really good about our Delaware Basin activity. I feel so good that we’re certainly willing to sign long-term deals, underwrite these pipes that desperately need to be in place. And I think that just underscores our commitment, to this area and our confidence in the position that we’re in. Thanks again for that question.

Kalei Akamine: Good stuff. My follow-up is on M&A. Wondering if you can talk a little bit about your philosophy. The last three deals that you guys have executed have been outside of the Permian, as you sort of highlighted there. The Permian is a need, given that it’s not subscale. But wondering if that decision to not transact in the Permian says anything about your view about the bid-ask spread in the basin?

Rick Muncrief: Not really. I think we’ve not transacted on major transactions. We have a really healthy ground game going on out there, I can tell you that. But we have not transacted in the Permian recently. We participated in a couple, but I can tell you that we are continuing to stick with our mantra of being very disciplined, and having a high bar in some of the premiums that we saw that may fit some people. It didn’t fit us time. And that’s just the way it works.

Kalei Akamine: Helpful. Thanks, guys.

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

Betty Jiang: Good morning. It’s great to see the operational momentum year-to-date. So when we look at the cycle time improvement, and then the better well productivity performance that – do you think any of the – these improvements that you have seen in the first half is sustainable going forward? And have you contemplated any of that into your second half guidance?

Clay Gaspar: Thanks for the question, Betty. We are constantly updating our forecast, both in timing, capital and, of course, production. And things like the operational improvements are a little bit easier to kind of grab a hold to and really bake into the forward forecast. When we’re finding unlocked upside in the productivity, we’re bouncing around. We’ve got a huge area, specifically in the Delaware Basin, but really around the company. We believe in time that we will be able to continue to unlock that. It’s a little harder to bake in to the current forecast on a month-to-month basis. And so, I would say there’s continued upside in that, that the teams are continuing to work on. We just – we want to make sure that what we put forward, we’re able to achieve.

And like I said, it’s a little easier to predict on some of the capital things, especially operational timing issues, casing design, some of the simul-frac changes. Those things we know we can do. As look to the well performance, we want to make sure that we’ve got a clear line of sight to what those productivities are. And within a certain area, we certainly understand where we can make improvements and we capture those as do.

Betty Jiang: Got it. That makes sense. And then on my follow-up, I guess, pretty similar along that line, parsing through on the CapEx side of things. With the higher CapEx or for 2024, guiding CapEx to the upper half of the guidance range and that comes with our activity as well. So a bit hard to parse out any cost benefits that you’re seeing across the play due to the efficiency gains, particularly in the Permian. So Clay, if you could help us any well cost deflation maybe on dollar per foot basis that would be really helpful?

Clay Gaspar: Yes, Betty. Thanks for the question. So as you recall, from 2023 to 2024, we forecasted 5% deflation gains during that period. I think we’ve continued to make improvements on that. At the same time, there’s an opposing race on these operational improvements and that capital kind of creeping in. So it’s been a battle of can we outrun the deflation? Or is the operational improvements kind of going to overtake a little bit. What we’re seeing so far is we are seeing the 5%, probably even beyond that 5% as we look to the balance of the year that is, so far, a little bit more offset by that operational improvements. The good news is, I want to make sure we connect on this. The good news is both deflation and the operational improvements helped the project economics.

These are both material gains for the wells capital efficiency and overall economics. And that, especially on the operational side are sticky. Those will translate into the future opportunities that we have, not just in the Delaware, but around the company.

Betty Jiang: Yes. That’s very helpful. Thank you.

Clay Gaspar: Thanks, Betty.

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

Charles Meade: Yes. Good morning Rick, Clay, Jeff and the rest of the Devon team there.

Rick Muncrief: Good morning, Charles.

Charles Meade: One question – one comment. One comment I’ve heard a few times in the wake of the Grayson Mill deal. Is that I’ve heard some people say, well, look at the math and they say a lot of that, particularly the Western portion is non-core. And so, I’m curious if you could – if you could give your comments on whether to what extent you agree with that? And maybe would say that was reflected in our purchase price or alternatively, whether that view is perhaps outdated, given that there hasn’t been as much attention on the bucket is or once was?

Rick Muncrief: Yes. Charles, good question. That’s something that I think we have seen overtime is that with efficiencies, and cost control, and all the things that we’ve learned over the last 15 or 20 years in these shale plays what was once Tier 2 has become core. And I think that what we’re seeing is some of this could arguably been 15, 20 years ago, Tier 2 plus. What we’re seeing is it’s, I’d call it between a Tier 2 and a core. So, we’re going to see some really nice returns. At the end of the day, when you start looking at the efficiencies, fact that we’re changing orientation slightly, we’re drilling three-mile laterals, instead at two-mile. We’re drilling three-mile wells in the same time or less than it used to take us to drill two and completions with these efficiencies.

What you see is at the end of day, whether it’s core, whether it’s Tier 2, Tier 3, Tier 4, whatever it may be. At the end of the day, all comes down to well level returns and what it does for your capital efficiency. And that’s how we price all of our transactions, anything we do or quite honestly, in our existing development program, with our current assets. So, we feel really good about it. And recall, it’s a basin that we’re very familiar with personally have been there. This is the 40th year, that I’ve been involved with in the Williston Basin is pretty incredible. So I’ve watched this evolve. And I can tell you, having 3,000 acres to develop, 3,000 acres to explore on over the – that’s a ton of running room in the next several decades.

So our geoscience team will go back to some of my prepared remarks, you’re really, really excited about what might lie ahead on top of what we already know, with our 500 new drills. So yes, we feel pretty good about it.

Charles Meade: Got it. That is helpful detail, Rick and then maybe a follow-up for Clay. Clay, you talked about that Eagle Ford redevelopment into DeWitt. Could just characterize a little bit more what that was. It sounds like there was at least partly re-fracs, but is that 100% re-frac? Or what was the composition of activity there?

Clay Gaspar: Charles, what we refer to as redevelopment, is basically taking units that look like they’re fully developed. And then looking for those downs pacing opportunities, and very unique to the Eagle Ford. What we’re finding is, able to feather in these wells that are much tighter spacing into fully developed units and these new development wells, essentially the redevelopment of that are coming in at phenomenal rates. It’s the gift that keeps on giving. Now when you complement that with re-fracs on some of the existing wells, we’re really finding a one, two punch that continues to provide lots and lots of running room in these areas that, from a map view look very developed. So that’s both in the Karnes and in the DeWitt County areas. We’re excited about that continued running room, and it gives us great encouragement about our position in the South Texas area.

Charles Meade: Thanks for that detail, Clay.

Clay Gaspar: Thank you, Charles.

Operator: The next question comes from Kevin MacCurdy with Pickering Energy Partners. Please go ahead.

Kevin MacCurdy: Hi. Good morning and thanks for taking my question. The Delaware is getting most of the attention and the low CapEx was especially impressive there. But the Eagle Ford was actually the bigger driver of the beat as we saw it. You just talked about some redevelopment wells there, driving the growth. Are there any other changes in Eagle Ford, such as the areas you were drilling or other efficiency gains?

Clay Gaspar: Kevin, this is Clay. Thanks for the question. We actually across the board beat, we had – I was listening to some of the calls and questions last night. Different analysts were picking up on different areas. And I took it as a great complement that across the board, our teams are really performing. So from another angle, you could say, wow, Williston really carried the day, or maybe it was the Delaware. But you’re right, Eagle Ford played a very critical role. Unique to our operations in the Eagle Ford, about half of our assets, we run in a more conventional way. About half of our assets in the DeWitt County area, we have a 50-50 partnership, a JV partnership there. And so are — be a good neighbor. We work with our partners.

And sometimes what that means is some quarters we get more opportunity, more activity on that JV than others. This happened to be a quarter, where it got a little bit more of the opportunity. And it’s just some really good, some really good potential and really good wells that we’re drilling there. So I think it’s nothing to extrapolate necessarily, just a little bit of a real nice quarter that we’ll take credit on and continue to move forward.

Kevin MacCurdy: Great. And to follow-up on Betty’s question, are the well cost savings you’re seeing per foot, is that across all of your areas? Or is that primarily just in the Permian?

Clay Gaspar: Well, Permian has advantage, because we currently have 16 rigs running there and three frac crews. And with that, those economies of scale and those reps and that competition, I mean, we rack and stack all 16 rigs every day on how they’re doing. And there’s a first place and there’s a last place and those guys know, those companies know, those engineers know exactly where they stand. And that healthy competition really adds to it. As opposed to an area like Powder that we have one rig, and we have a part-time frac crew that’s a challenging area, to really apply those learnings and really that scale. So when we fast forward and we look at some of those other opportunities, Powder comes to mind is, one, that what is the potential on cost savings and efficiency, there’s so much more to be had when we do end up, or able to lean into that.

And so really trying to understand what that potential is, and evaluate when does that fit eventually into our portfolio I think that’s part of the consideration. Now we’re always trying to export the learnings from Delaware and from Eagle Ford and from Anadarko, to all the other areas as well, and they learn from each other. So that competition doesn’t just stay inside the basin. We try to provide that that healthy competition and collaboration kind of around the company. And now that we have the Grayson team about to roll in, we’re excited about, again, sharing some of those learnings, learning back from them, and that’s the nature of culture of this continuous improvement that I pointed to in the prepared remarks.

Kevin MacCurdy: Thanks for the details, Clay.

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

Paul Cheng: Hi. Good morning. Thank you.

Rick Muncrief: Good morning.

Paul Cheng: Question, please. First, I think, is for Clay. I want to go back into your comment about Powder River Basin. To some degree, that you become a bit chicken and egg, right? Because right now that you are not having enough of the activity, so you won’t be able to improve the unit cost and everything at a substantial pace, or at least that comparing to Permian, or that even Bakken ones that you finished with Grayson. But as a result, that you might have strengthened capital. So I mean, how exactly we should look at it and internally than how you’re going to balance that? And what kind of time line we should have in terms of moving to the next level at Permian, in the Powder River Basin for you?

Clay Gaspar: Yes. Thanks for the question, Paul. I appreciate it, and I think it’s a really good one. As we think about the Powder, I mentioned it as a complementary asset. The great news is we’re going to be able to ride the back of the Delaware Basin and the other really strong basins that are much more mature and developed while we unlock the potential in the Powder. So plan on us having kind of one to two rigs in that realm. And what we’re really focused on is productivity understanding spacing, applying some of the learnings that we can around well construction that are material improvements. I mentioned a couple of things. There’s a new casing design we just applied. It is a very material cost savings. Those are the kind of things that we’ll be able to get our arms around.

But it’s really on the productivity side, the consistency side that allows us to really understand that productivity side of the equation. Now on the cost side, there’s a 100% certainty in my mind that when we scale this up, costs are going to come down materially. And that’s on the back of every other basin we’ve ever worked in, and we’ve had success with that. And I also know we will never achieve the full potential until we get that. That’s the chicken and egg conundrum that you pointed to, I think what we’ll get to is we’ll run our one to two rigs, we’ll be able achieve some of those productivity wins. We’ll be able to achieve some of the cost wins as well. But we also can look over the fence. A couple of companies have a little bit more activity.

And then we can extrapolate our learnings from the other basins to allow with certain confidence what the potential can be and when will that really start to play a bigger part. To answer the second part of your question, Look, we’ve got time. Time is on our side. We’ve got long-term leases. We have a great inventory that allows us to derisk this play in time. So don’t think of any of my remarks as all of a sudden, there’s going to be a rush capital towards Powder. I just want to keep it on your on your horizon as really valuable piece of our portfolio that probably has, zero value out there in the world from our share price. But one day, we’ll be an incredible part of our return of overall value creation and return of capital to the shareholders.

And in the meantime, we will continue to derisk this and unlock this potential in a very systematic way.

Paul Cheng: Clay, should we look at your development timeline in a sense that based on the performance of the other basins, like that you will wait until, for example, on the Permian, we start to get a bit more aging. And then, you will slow down over there and then you increase the pace in the Powder River Basin, or that you doesn’t really look from that angle?

Clay Gaspar: Yes, certainly, we evaluate capital. I mentioned a strategic board meeting we have annually in September, and this is where we’re looking 10 years out and how do all these opportunities fit. What I also mentioned on Slide 11 is the incredible inventory we have in the Delaware Basin. There’s a big chunk of that, that’s still yet to be kind of on the development kind of Tier 1 ready to go. As we continue to unlock Delaware asset potential, which we still have a lot of unlocking to do there, that puts other things probably a little further out on the runway. But I think it’s incumbent on us, to make sure that all of these potentials are understood well in advance of us needing them. And so what I would expect in time, maybe second half of the decade, there’ll be more of an opportunity for the Powder to really step in.

In the meantime, the front half of the decade, we really need make sure that we’re ready for that. And what my signal to you today is we’re really pleased with that steady progress that we’re seeing.

Paul Cheng: Perfect. Maybe a real quick one, final one from me. Can you compare Grayson with your legacy Bakken in terms of the well cost and the operating costs? Is it one is better than the other or similar? Thank you.

Clay Gaspar: Well, there’s some important differences. The first thing I would point to and the reason we’re so attracted to the Grayson is running room. Additional 300,000 acres, an incredible running room, well positioned for a lot of three-mile development gets us really excited. Now, objectively, the East side of the basin on the reservation where we’re at in our legacy position is just better rock, which has been an incredible asset for us to lean on from a decade from the WPX side. And so, we’ve created some incredible value from that. As we look on the Grayson side, incredible running room, Rick mentioned a lot of stuff, not too long ago was Tier 2 acreage. So it hasn’t been developed. And then importantly, with the nature of this kind of rock, we think there’s more upside potential in things like refracs and further upside potential from enhanced oil recovery and other ideas further down the road.

So really excited about Grayson. From a well cost standpoint, I would say really too early to tell. It will be in the same ballpark. But look for us to gain some efficiencies, as we really think about those rigs holistically for the entire basin, we’ll gain some great efficiencies there as well.

Rick Muncrief: Hi Paul, it’s Rick. I’ll interject a couple of other things. Number one is, yes, number one is that I think the Grayson project, the Grayson acreage, you’re going to have slightly less oil cut percentage. But I also think we’ll see better margins, because of the control or the inflows we have with the infrastructure there that, which we don’t have overall on the legacy position. So, I think that’s going to be a net plus for us on that. So, we’re excited about it. But thanks for the question.

Paul Cheng: Thank you, Rick.

Rosy Zuklic: We have reached the end of our Q&A session. We want to appreciate everyone for your interest in Devon. And if you have any further questions, please reach out to anyone in the Investor Relations team, and hope everyone has a wonderful day. Thank you.

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