Devon Energy Corporation (NYSE:DVN) Q1 2024 Earnings Call Transcript

Devon Energy Corporation (NYSE:DVN) Q1 2024 Earnings Call Transcript May 2, 2024

Devon Energy Corporation isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Welcome to Devon Energy’s First 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 Mr. Scott Coody, Vice President of Investor Relations. Sir, you may begin.

Scott Coody: 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.

Rick Muncrief : Thank you, Scott. It’s a pleasure to be here this morning. We appreciate everyone taking the time to join us. By all measures, Devon delivered an outstanding set of results in the first quarter that surpassed the operational and financial targets we had set by wide margin. This start to 2024 demonstrates the impressive momentum that we’ve quickly established setting the stage for our business to continue to strengthen. At this time, I want to personally thank our employees, our service providers and our infrastructure partners in helping us get 2024 off to a great start. For the remainder of my comments for today, I will focus on the drivers of our first quarter outperformance and the factors underpinning our improved outlook for the remainder of the year.

So to start off on Slide 6, let’s do a quick review of our first quarter results where we had several noteworthy highlights. Starting with production, our delivered volumes came in about 4% higher than planned for the first quarter, averaging 664,000 BOE per day. This production beat was across all products and driven by three key factors. First, and the most significant contributor to this performance was the excellent well productivity we achieved from the 100-plus wells we placed online during the quarter. On average, these high-impact wells exceeded our top curve expectations with strong well productivity in the Delaware Basin, once again, driving our results. Overall, this activity achieved initial production rates that were more than 20% higher than those that we placed online last year.

As we progress through this year, I anticipate that these strong recoveries will continue. Secondly, another key factor that drove production higher in the quarter was the improved cycle times we delivered across our drilling and completion operations. Clay will go into much more detail a little later. But simply put, these efficiency gains allowed us to bring forward activity in the quarter and capture more days online than we had planned. And third was a factor that positively contributed to our performance during the quarter was the easing of infrastructure constraints across our Delaware Basin assets. This improvement was directly related to the steps we’ve taken along with our third-party partners to invest in the build-out of incremental gas processing, compression, water handling and electrification.

These crucial capacity additions have positioned us to achieve better run times for our base production and allow us to deploy more activity to the core of this world-class basin. Another notable achievement from the quarter was this team’s effective cost management. This was demonstrated by delivering operating costs that were 3% lower than guidance and capital expenditures that were in line with expectations even with an accelerated pace of activity. This positive start to the year puts us in a great position to deliver better cost efficiencies in 2024, especially if we realize incremental savings from deflation as we go through the year. Cutting to the bottom line, the team’s comprehensive execution across all aspects of the plan resulted in our 15th consecutive quarter of free cash flow showcasing the durability of our plan to consistently create value through the cycle.

With this free cash flow, we continue to reward shareholders through our cash return framework, which was led by stock buybacks and supplemented by another attractive dividend payout. Now moving ahead to Slide 12. And with the strong operational performance achieved year-to-date, we are raising guidance expectations for the full year of 2024. As you can see on the top left, a key contributor to this improved outlook is our 2024 production target increasing by 15,000 BOE per day or 2% to a range of 655,000 to 675,000 BOE per day. To reiterate what I touched on earlier, these higher volume expectations are due to the better-than-expected well performance achieved year-to-date and our confidence in the quality slate of projects that we have lined up over the course of this year.

Importantly, we are delivering this incremental production within the confines of our original capital budget of $3.3 billion to $3.6 billion. This level of investment is expected to maintain a steady production profile of about — for about 10% less capital compared to last year. This program is fully funded at ultra-low breakeven of around $40 per barrel, which equates to one of the lowest breakeven levels of any company in the industry. With our improved full year outlook, we are now positioned to generate greater than 15% more free cash flow in 2024 versus last year at today’s pricing levels. This translates into attractive free cash flow yield of 9%, which is nearly 3x higher than what the broader market can offer. With this growing stream of free cash flow, we remain unwavering in our commitment to capital discipline and will seek to reward shareholders with higher cash returns.

With our flexible cash return framework, we will allocate our free cash flow toward the best opportunity, whether that be buybacks or dividends. Given that the equity market is still heavily discounting valuation to the energy sector, we plan to continue to prioritize share buybacks over the variable dividend to capture the incredible value that Devon offers at these historically low valuations. So in summary, 2024 is off to an excellent start. We delivered on exactly what we said we would do and much more in the first quarter. Our business continues to get better and build momentum, and this is reflected in our improved outlook for the year. And with the current valuations in this space, the best thing we could do is buy back our stock to capture this value.

It’s going to be a great year for Devon and the team is energized to build upon this strong start. And with that, I’ll now turn the call over to Clay. Clay?

Clay Gaspar: 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 a 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 wells impact — 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 two years. On Slide 8, while we delivered high economic results across the basin, I’d like to drill down on 3 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 a thoughtful upfront planning and improved efficiencies from our simul frac operations, the team brought Van Doo Dah online nearly two 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 further — this success further reinforces why I believed the STACK pay potential in Cotton Draw to be one of the best tranches of acreage in all of North America. Another networthy project that achieved the highest initial rates of any project in the quarter, was a CBR 1510 in our Stateline area. This three-mile Upper Wolfcamp development was made possible by an acreage trade, 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 are also extraordinary projected to exceed 2 million BOE per well.

And lastly, I would like to cover a key appraisal success that we had in the quarter and 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 shift 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 ’25 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 board segment — across the broader segment of our activity has been a key driver of compressed cycle times, but the high-grading of rig fleets also drive down overall well cost is contributing.

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 just 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’ remaining inventory of the top Delaware Basin producers. As you can see from this credible third parties 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 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 [indiscernible] 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 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 completions 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 price, our capital activity was limited to 1 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 five 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 price 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. Jeff?

Jeff Ritenour: 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 four to three 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 price of oil has provided a meaningful impact to 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 cost 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. And 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.

Rick Muncrief: 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 into Delaware. Number three, furthermore, this improved outlook is also manifested 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. And lastly, our long-duration resource base is one of the deepest of any company out there. We continue to find ways to add resource. 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.

Scott Coody: 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.

See also 30 Wealthiest People in India and Top 10 Artificial Intelligence (AI) SEO Tools in 2024.

Q&A Session

Operator: Thank you. Our first question comes from Arun Jayaram with JPMorgan. Your line is open. Please go ahead.

Arun Jayaram: Yes, good morning. Team, I was wondering if you could elaborate on the improvement in the midstream situation in the Delaware Basin. And just talk about — and one of the questions coming in is just is there any conservative built in to the second half guide given the fact that you outperformed in 1Q despite some of the weather issues?

Jeff Ritenour: 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, $115 million a year in the Delaware to build out that compression in the gathering. And as Clay mentioned in his prepared remarks, that served us really well as we walked in here to 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 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.

Arun Jayaram: 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?

Clay Gaspar: 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. And then also, obviously, refining our techniques that we’re using to do some of these operations.

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 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 is 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, highly encouraged. I mean, in every one of these very prolific basins, it’s still — 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 do we create value from these amazing opportunities.

And so more to come on that.

Arun Jayaram: Great, thanks a lot.

Operator: We now turn to Neil Mehta with Goldman Sachs. Your line is open. Please go ahead.

Neil Mehta: Yes, good morning team and good to see that inflection in the Delaware this quarter. I’d love you guys to spend a little bit of time talking about 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?

Jeff Ritenour: 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 repo 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, $275 million a quarter, currently, that 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 a 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.

Neil Mehta: 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?

Jeff Ritenour: 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 the downward trajectory of pricing here over the last, call it, 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 us 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 data 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 six 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 leading 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 with another 18, 24 months.

Neil Mehta: Makes sense. Thanks, Jeff.

Operator: Our next question comes from Nitin Kumar with Mizuho. Your line is open. Please go ahead.

Nitin Kumar: Hi, good morning Rick and team and good to see the deliveries 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?

Clay Gaspar: Yes. Thanks for the question. And the clarification, both Rick and I covered this remarks [indiscernible]. Number one, I’m sorry about that. Sorry, thanks for asking the question and allowing us to clarify this. We both — Rick and I covered this in our prepared remarks, but there’s three big contributions to the outperformance. Number one on the list, probably 60% of the outperformance was well productivity. That really drove the outperformance. Second was the efficiency at which we’re bringing to them. We had a couple of more days online here and there. Cumulatively, that adds up. And then third, very importantly, from a base standpoint, both from a midstream standpoint, from a weather standpoint, just how we’re operating our wells, we really outperformed historical performance there. So thanks for the opportunity to clarify that. Maybe we weren’t clear on that.

Nitin Kumar: 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?

Rick Muncrief: Number one, Nitin, we are very comfortable with our portfolio. We think it’s got — we have one of the highest quality portfolios and we’re in multiple basins, what really, I think plays to our advantage. We’ll always look at things, but our bottom line is we have a very, very high bar, and we were very comfortable with where we’re at. Can we find something that makes us stronger, and we would consider that without a doubt. But at the end of the day, our game plan has not changed. High bar — we recognize the quality of our portfolio. You’re seeing the results coming from this portfolio. We feel very good about sustainability. And that’s not just our view. It’s — you can look at — as a matter of fact, we left — we put a slide in our slide deck just showing our quality of our portfolio versus many of our peers.

And so — at the end of the day, our game plan is, year-after-year, we want to be right at the top of the leaderboard on capital efficiency, and we’ll continue to get that free cash flow we generate back to our shareholders. So — but as far as the question around consolidation, I think our game plan has been solid for several years now. We had participated. We helped kick a lot of the consolidation all, quite honestly, and worked really well, and that’s how we’ve developed this great portfolio that we have.

Nitin Kumar: Great, thanks for the color guys.

Operator: We now turn to Scott Gruber with Citi. Your line is open. Please go ahead.

Scott Gruber: Yes, thanks for taking my question. 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?

Clay Gaspar: 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, 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 four frac crews, that we are consuming some of the pent-up DUCs. And then we’re running three 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 quarters 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.

Scott Gruber: 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 into the Eagle Ford and the Permian and start to loosen the rig and the frac markets up?

Clay Gaspar: Scott, we are — 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, more efficient completions, which you know can put a little bit of positive pressure on that 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.

Scott Gruber: I appreciate the color. Thank you.

Clay Gaspar: Thank you.

Operator: Our next question comes from Neal Dingmann with Truist. Your line is open. Please go ahead.

Neal Dingmann: Good morning guys. Thanks for taking my call. Rick, just one for you or Clay, I guess. Looking at Slide 7 on that Delaware plan, it looks like it’s going quite good. I’m just wondering, if we looked at that plan, I mean, maybe it’s too far to get — start talking about ’25. But when we look at the plan for 2025, how different play when we start seeing those areas that are laid out, like the ’25 plan look versus ’24?

Clay Gaspar: Neal, thanks for asking the question. We have — we are reverting back to about the same proportions that we were pre-’23 that we are in ’24 now. And so that’s commensurate with the approximate portfolio ratio that we have, New Mexico to Texas, overall Delaware Basin to the balance of the rest of the company. And so think of ’24 as a little bit more of the norm. ’23 was a little bit of an anomaly. We moved from about 70% in New Mexico to roughly about 60% in New Mexico, and that little bit of inflection was able to be seen in the overall average well productivity. So moving back to 2024 is what we’re doing now is a little bit more, I would say, kind of steady state for what we expect rolling forward for ’25 and really and beyond.

Neal Dingmann: 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?

Clay Gaspar: Yes, I would say roughly. We will continue to evaluate near-term opportunities there. We continue to be excited about the depth of inventory. We continue to find new things out ahead of us that really aren’t even reflected in our current inventory models. So that continues to keep us excited. We’re always evaluating what kind of screens to the front of the list. And I think this kind of is really an answer to both of your questions. Remember, the wells that we’re bringing online, specifically in the Delaware because it’s just — it’s leading our performance. A couple of years ago, these didn’t screen nearly where we’re seeing the results today. So our optimism about a couple of years from now, what’s really coming up in the portfolio in all of our basins remain very high based on the fact that we’ve got a lot of smart people chipping away at really good ideas on how to always improve those recoveries a little bit more and operationally just do it a little bit more efficiently.

Neal Dingmann: Makes sense. Thanks, Clay.

Clay Gaspar: You bet, Neal.

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

Roger Read: Yes, thank you. Good morning. 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 that — is there another use of cash we should think about here in terms of either bought 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?

Jeff Ritenour: 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 to the balance sheet to handle those upcoming maturities, and then we’ll see where things go from there.

Roger Read: Fair enough. The other question just to come back on the, let’s call it, broadly the efficiencies — capital efficiencies, completion efficiencies that are on Slide 9. If you had to think about it from a — kind of placing a credit, let’s say, within the overall deflationary environment, the difference between lower rig rates or lower frac costs relative to the improvement? What would you say is the more important one?

Clay Gaspar: Between those two, I would probably push a little bit more to the completions because you’re — it’s just a bigger ticket. But I would put ahead of that, some deflation we’re actually seeing in pipe. We — in the steel costs in ’23 was by far the highest category. We’ve seen that roll over pretty materially. Hopefully, there’s more to come there, but we’re pretty objective about overall well cost. We feel good about our guide where we’re at now. As I mentioned earlier, I’m hoping for a little bit more inflation, but I’m also very realistic that the efficiency gains that we have make me hold the line on our capital guide.

Roger Read: If I could, I just kind of wanted to clarify the question. So if I’m thinking about the efficiency gains, like, for example, more footage per day, relative to a lower cost, just flat cost of services, kind of which 1 do you think you could lean into more aggressively here? Is it continued efficiencies on a footage per day basis or lower cost just directly from the service companies?

Clay Gaspar: I think we continue to make great ground on the efficiencies, the days foot per day — days spud to TD. I see those numbers continuing ahead the right direction. The inflation, deflation, actual rig cost itself, that’s somewhat — we run with the market there. We’re always pressing for the best opportunity, and we always evaluate service providers based on their own capabilities and what that cost is. So we’re not beholding to one particular company or one particular category, we’re pretty objective about taking the best opportunity to create the most value for our bottom line.

Operator: We now turn to Kevin MacCurdy with Pickering Energy Partners. Your line is open. Please go ahead.

Kevin MacCurdy: Hey, good morning and 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?

Clay Gaspar: 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.

Kevin MacCurdy: 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?

Rick Muncrief: We’ll always look at what we think is the right time when midstream multiples are clearly differential, if you will, to where we’re at. And how that butts up to our strategy and making sure that we continue to deliver our commodity, and we get the — we have the influence that we need. And so it will probably come in due time, but it’s something we’ll continue to monitor, and we try to keep a pretty close pulse on that. Jeff, anything else you want to add there?

Jeff Ritenour: No, I think you said it well, Rick, which is it really is a function of the evolution of the kind of the life cycle of the asset and where we are on that. And as Rick mentioned, we’ve tried to be opportunistic with those investments, certainly 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.

Kevin MacCurdy: Great. Thank you guys.

Operator: Our next question comes from Charles Meade with Johnson Rice. Your line is open. Please go ahead.

Charles Meade: Good morning, Rick, Clay, and Jeff and to the rest of the Devon team there. Clay, I know you feel there’s a number of questions this morning along the lines of you guys had this bang up quarter to what extent should we expect that to continue. And I understand you’re reluctant — you should be reluctant to commit to that publicly. You’re probably reluctant to commit to it internally. But I’m going to try to trick you when you’re talking about it in a different way. And here’s the question. It was really helpful the way you guys allocated the — be it 6% well performance within the balance between cycle times and easing infrastructure constraints. But the question is, to what extent is that — is there interaction between that well performance and the easing infrastructure constraints.

So my understanding is that there’s a lot of new well pads in the Delaware that could be producing higher, but for these above bound constraints. And so — is that easing above your street that enabled you to deliver those — the rates that you’ve highlighted on those three Delaware pads?

Clay Gaspar: I think that’s a great question, and I’ll take a little bit of that, I’ll take some of that bate and pursue it. And by the way, we’re always happy to talk about operations, beats the heck out of something else that’s more asymmetric to our objectives. Referring back to Slide 9, we talk about two things: the well productivity and the completions efficiencies. And then in our — both Rick and my prepared remarks, we talked about really three components and adding on that base. That base outperformance was really critical as well. As I think about overall proportionate, about 60% of the outperformance really was the well productivity, maybe 20 or so was bringing forward those projects more days online, and about 20% was just uptime really associated with less constraints than we saw in ’23 and really historically.

Now that does not say that we didn’t have any constraints. There’s advantages and there’s disadvantages of working in the hottest basin around the world. And that’s really the Permian and more specifically, what we’re seeing in the Delaware. Jeff’s gotten questions on the midstream buildout. We’re very highly tuned in on that. But it’s not just gas. We watch water, we watch oil build-out, processing, the electrification, all of those categories, we have to juggle in a four or five dimensional kind of just way to develop this incredibly prolific resource. The other complication specific to the Delaware is the number of landing zones, and that continues to evolve. We highlighted the Wolfcamp B as something that will probably play a larger differential role.

So as we roll that in, we also need to think about the changes to that infrastructure and the needs. One of the questions you asked along the way was, do our wells have anything kind of held back because of infrastructure constraints. And I would say, categorically, yes, there’s always something. We’re not going to push volumes into a system that just doesn’t want those systems. We’re not going to pay — we try and minimize paying basically disposal fees for gas. And then we also are very thoughtful about our flaring percentages. We’ve incredibly drawn that down. We made really good progress over the last few years. we certainly don’t want to reverse course on some of those gains. So there’s a lot going on. Really, really pleased with the team’s performance and happy to be here to represent the team on such a successful quarter.

Charles Meade: 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?

Clay Gaspar: It is the new wells. I’m separating 60% for the new wells, that 20% that I talked about in the base is the existing wells kind of the other base activities that are also performing — outperforming what we had baked into the forecast.

Charles Meade: Got it. Thanks for the detail.

Clay Gaspar: You bet, Charles.

Operator: We now turn to Scott Hanold with RBC. Your line is open. Please go ahead.

Scott Hanold: Yes, thanks. Hey, 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 interesting to hear any kind of color on the high grading. And what can we 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?

Clay Gaspar: 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 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 [indiscernible] 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.

Scott Hanold: 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?

Clay Gaspar: 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 valley 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.

Scott Hanold: Got it. 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?

Clay Gaspar: Well, it’s interesting. We talked about the Wolfcamp B a couple of quarters ago, kind of highlighting success there as well. It was just in a different part of the basin. The B obviously extends all the way across the Delaware Basin. This was an area that we really haven’t drilled. It’s a little bit more Northeast on our position in the Thistle area. And it’s a little less mature, certainly from the B. I think there’s three wells that have produced the B, the first two were just kind of so-so, and so our expectations were pretty moderate. But again, as we’re thinking about developing these areas, we wanted to really put a modern completion on and give our best kind of try and see what it looks like. It’s significantly outperformed.

And so with the approach that we’re taking today, we’re really excited about that differential uplift. The 50 wells is really just [indiscernible] area. We have other B wells that we will be bringing on in other wells — excuse me, other areas of the basin as well, those are above and beyond the 50, we’ll continue to hunt for and more opportunity. The reason we highlighted this Thistle is this is not reflected in our inventory. This is more of that upside that we’re bringing forward that now competes very favorably for the capital investment today.

Scott Hanold: Thank you.

Clay Gaspar: You bet, Scott.

Operator: Our final question comes from Matthew Portillo with TPH. Your line is open. Please go ahead.

Matthew Portillo: Good morning all. Maybe a question for Clay to start. On the Anadarko, good to see a slowdown in the drill bit capital here. It sounds like dropping down to two rigs given the commodity price environment. I was curious if you have any updated thoughts on the 60 to 70 [indiscernible] for the year? And then, I guess, looking ahead to a more constructive environment beyond kind of 2024, what’s the opportunity set to potentially accelerate this asset in a more constructive gas price environment?

Clay Gaspar: Thanks for the question. We’ve got a great partner with Dow. And so this is something that we want to make sure that we’re being good partner, and we’re working in coordination with them. So I certainly don’t want to get ahead of myself. What I can tell you is we’ve been very aligned, continue to appreciate not just the value creation from the partnership, but the nature of the partnership. I would say if the right opportunity presented, my belief is that we would be aligned in accelerating. Now what I have to tell you is I’m looking at the forward gas curve — and it’s just — it continues to be pretty challenging. Again, with the balanced portfolio that we have, our ability for the Delaware Basin to really carry the company, we just don’t see the need to push dollars into an area that’s not being fully rewarded.

Now that said, with the Dow Carry and with the work that our midstream team has done to really extract the most value we can for these this commodity, we are doing actually pretty well on these returns. Not Wolfcamp A well, but really know that we’re still creating value. So we’ll continue to run two rigs in the Dow JV area, continue to look for those opportunities above and beyond and then even extend potentially the Dow JV beyond where we’re at today. Again, great partnership, enjoy working with that team, and I think we both benefited very well from it.

Matthew Portillo: Perfect. And then maybe just a longer-term question on the gas front. Curious if you might be able to provide us an update on — is how you’re thinking about your LNG strategy and kind of the marketing of gas molecules on a global perspective? And any updated thoughts on the Delfin [ph]?

Jeff Ritenour: Yes, Matt, this is Jeff. Yes, we continue to have interest in getting some exposure to the water as it relates to both on the oil and the gas — on the gas front. Specific to LNG, we’re having active conversations with different folks, including Delfin, as you mentioned. That continues to progress. No new updates beyond what you’ve heard from us in the past. But without question, we want to get some exposure to the LNG market as it relates to our gas molecules. And as I mentioned earlier, with the Delaware gas, we’re in a significant portion of that to the Gulf Coast. Some of that goes into the Katy market. We’ve got incremental capacity that takes us away from Katy into the Louisiana kind of the hub where a lot of that LNG demand resides today and will get built out into the future. And so we feel like we’re well positioned to take advantage of that incremental demand and again, having active conversations with multiple parties.

Matthew Portillo: Thank you.

Scott Coody: 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.

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