Devon Energy Corporation (NYSE:DVN) Q2 2023 Earnings Call Transcript

Devon Energy Corporation (NYSE:DVN) Q2 2023 Earnings Call Transcript August 2, 2023

Operator: Ladies and gentlemen, welcome to Devon Energy’s Second Quarter Earnings Conference Call. [Operator Instructions] 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 to everyone for joining us on the call today. Last night, we issued an earnings release and presentation that cover our results for the second quarter and our outlook for the remainder of 2023. Throughout the call today, we will make references to the earnings presentation to support our 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 will turn the call over to Rick.

Rick Muncrief: Thank you, Scott. Pleasure to be here this morning. We appreciate everyone taking the time to join us. Devon’s second quarter performance can be defined as another one of solid execution on all fronts as our business continued to strengthen and build operational momentum throughout the quarter. The attractive per share growth we have consistently delivered quarter after quarter demonstrates the efficiency of our disciplined business model, the quality of our Delaware-focused asset portfolio, and the team’s execution capabilities and the benefits of our cash return framework. The chart on Slide 4 provides a very compelling visual of this success, showcasing our impressive track record of value creation. Since we unveiled the industry first framework in late 2020, we have deployed $12 billion towards dividends share buybacks, debt reduction and accretive bolt-on acquisitions.

The cumulative value of these actions equates to nearly 2x the value of Devon’s pro forma market capitalization from just a few years ago. As you can see from our diversified actions to-date, we have carefully designed our cash return framework to be nimble with the flexibility to allocate free cash flow across multiple avenues to optimize financial results through the cycle. Importantly, this disciplined execution has been rewarded by the market with our equity performance, achieving the highest return of any stock in the entire S&P 500 over this period. Now, let’s go through some of our second quarter highlights and operating trends in greater detail. Beginning with production, the team did a great job, growing oil volumes by 8% on a year-over-year basis this past quarter.

This result surpassed midpoint guidance expectations and for us set a new all-time high oil production record for the company by averaging 323,000 barrels per day in the quarter. Additionally, this volume growth was supported by an infrastructure that includes several strategic midstream assets that we have selectively invested in through the years and have taken equity stakes in an effort to enhance the result from our core E&P operations. A key driver of this record-setting result was higher completion activity in the Delaware Basin. By leveraging the benefits of a temporary fourth frac crew and consistently improving cycle times, we were able to bring online 76 new Delaware wells in the quarter, which was a few more than we originally planned due to efficiency gains.

Importantly, the well productivity from this batch of wells in Delaware was excellent and included a Wolfcamp B appraisal success that strengthens the depth and quality of our resource in the area. We also had a successful redevelopment test in the Eagle Ford and advanced a handful of other interesting appraisal projects across our diversified asset base that it reinforces our confidence in the resource upside that currently exist across our portfolio. Looking ahead, with higher levels of completion activity in the second quarter, we expect our production profile to continue to strengthen the upcoming third quarter. A good visual of this operational momentum can be seen on Slide 7, with oil volumes expected to grow to a range of 322,000 to 330,000 barrels per day in the upcoming quarter.

As I touched on earlier, the capital spending to drive this growth trajectory was a touch ahead of expectations due to very strong execution from our drilling and completion teams that brought forward activity into the quarter. Clay will spend time and cover this topic later, but I am extremely proud to share that we’ve set several operational records at both the basin and company level, contributing to the record-setting drilled and completed feet per day metrics we have achieved year-to-date. In addition to our strong operating efficiencies, our business is also beginning to benefit from service cost deflation as contracts are refreshed. This is driven by reduced activity from natural gas-focused companies and private producers over the past few months resulted – resulting in improved availability of services and cost deflation in virtually every category.

Although this is a very dynamic environment, we’ve observed the most downward pressure to date in the areas of tubulars, rig rates, fuel and other miscellaneous drilling services that will begin to positively impact our cost structure as we enter the end of this year. We also anticipate price movement with pressure pumping, which is our largest cost category in a very near future. While it’s still somewhat premature to say what and set what our firm outlook for 2024 is, our expectations for deflationary trends should continue. We have the potential for meaningful savings from peak well costs as pricing improvements gradually flow through our cost structure over the next year or so. With a free cash flow model that our business generated, we had another great quarter of cash returns.

We returned $462 million to shareholders through our fixed plus variable dividend which we have paid out now for 12 consecutive quarters. We also have an active buyback program that resulted in the repurchase of nearly 4 million shares over the past 3 months. We believe this balance between dividends and buyback offers investors the powerful combination of an attractive yield and steady per share growth through the cycle. Now moving to Slide 11. With the progress that our business has made year-to-date, we are well on our way to meeting the capital objectives associated with our 2023 plan. The momentum we have established places us on track to deliver a production per share growth rate of approximately 9% for the year. Importantly, the activity required to fund this growth is self-funded at a $40 WTI price or approximately half of where we are today and is delivering returns on capital employed greater than 20% at today’s commodity prices.

While once again, it is too early to provide firm guidance for next year. The trajectory of our business sets us up for a strong outlook in 2024 as well. Given current market fundamentals, we plan to invest at levels that will sustain our productive capacity and any improvements that we see from lower service costs will accrue to our shareholders in the form of higher free cash flow generation. This disciplined pursuit of value over volume positions us to continue to deliver another year of differentiated cash returns and highly competitive returns on invested capital versus the broader market. And now with that, I’ll now turn the call over to Clay to cover our operational highlights. Clay?

Clay Gaspar: Thank you, Rick, and good morning, everyone. Our second quarter operating results demonstrated that our business is performing at a high level and building momentum as we head into the second half of the year. As Rick touched on, this positive trajectory is underpinned by improving capital efficiency from faster cycle times, improving service costs and positive appraisal results that will contribute to our production profile and financial results over the balance of this year and more significantly into 2024. We Today, I plan to provide a brief overview of the second quarter results across our assets as well as highlight some upcoming catalysts, the most significant contributor to Devon’s second quarter operating success, so once again, our franchise asset in the Delaware Basin.

As you can see on Slide 8, more than 60% of our capital activity was deployed to this prolific basin, allowing us to run a consistent program of 16 rigs. With the fourth completion crew of work in the first half of the year, we were able to place 76 wells online in the second quarter, up more than 80% compared to the first quarter. This elevated completion activity grew our Delaware production to 420,000 BOE per day and is expected to underpin volume growth in the third quarter as well. While we had great results across our acreage position, a key project I would like to highlight from the quarter was our Mule development in Eddy County, New Mexico. We’ve talked in the past about the important appraisal work that we do each year with 10% to 20% of our capital budget.

The Mule pad is an example to provide you some visibility into the fruits of this labor. This 11-well project successfully codeveloped multiple landing zones within the Wolfcamp with particularly exciting results from the appraisal of deeper Wolfcamp B benches. The initial results from these 6 wells targeting the Wolfcamp B landing zones average greater than 3,100 BOE per day with 44% oil cut. Per well recoveries are on trend to exceed 2 million barrels of oil equivalent. Importantly, these highly commercial appraisal results de-risk and enhance the economic expectations on approximately 100 Wolfcamp B locations in the Cotton Draw area. Furthermore, these deeper Wolfcamp locations are expected to be highly competitive within our capital allocation framework going forward.

The Delaware team also continued to make progress advancing drilling and completions efficiencies across our operations in the basin. In the Wolfcamp, we improved drilling productivity by about 10% on a per foot basis over the past year, while some of our best spud release times for 2-mile laterals pushing below 15 days. Completion efficiencies have also steadily improved, with our cycle times decreasing by 9% year-to-date and compared to 2022. Averaging a record completion pace of more than 2,200 feet per day in the quarter, this operational progress has been accomplished in conjunction with an even higher safety and environmental focus and expectation. The great work our team has done to drive improvements across the entire planning and execution of our resources coupled with a broader service cost deflation trends are positioning our business to be even more efficient as we head into 2024.

Moving to the Eagle Ford, our 3-rig program resulted in 29 gross wells placed online during the quarter. This activity which was concentrated in the recently acquired acreage in Torrance County drove a 9% increase in productivity versus the previous quarter. This margin – this high margin growth was driven by strong well productivity achieved from a balanced mix of development and appraisal activity designed to refine the next stage of development for this prolific resource play. Our top development project in the quarter was headlined by LP Butler pad. This 4-well pad developed a highly charged theme of pay in the volatile oil window of the play that exceeded pre-drill expectations, reaching an impressive average 30-day rate of 3,600 BOE per day, with a 56% oil cuts.

On the appraisal front, a key success in the quarter was the [indiscernible] unit. This development project in Torrance County tested infill spacing, ranging from 140 to 150 – excuse me 180 foot and roughly 30 wells per section. The initial 30-Day rates from this package of wells averaged 2,000 BOE per day, resulting in highly commercial returns, that adds the depth and quality of our inventory in the play. Also, adding to the commerciality of this tighter spacing was our drilling performance where we broke a company record averaging over 2000 feet per day, which included the fastest bud rig release time in company history of only 5.7 days. As we look to allocate capital for 2024 and beyond, the positive operating results we have achieved year-to-date served as valuable data points to optimize future development activity in the Eagle Ford and other and further deepens our convictions of the resource upside that a crop that exists across this entire field.

Moving to the Williston, volumes began to rebound in the second quarter growing 4% quarter-over-quarter to 56,000 BOE per day. This growth was driven by improved weather, higher up times on existing producers, and successful adjustments to completion and production techniques for some of the new well activity. These completion and production modifications consisted of change to larger profit size designed to mitigate mobility of sand and a shift in artificial lift techniques to improve well uptime. With the favorable flow-back results on two pads that have deployed these techniques. We have high confidence that the wells productivity will improve as we see progress throughout the year. Looking at inventory, we now have more than 150 wells remaining and identified significant refract opportunities across hundreds of producing wells in the field, providing us the optionality to deploy steady reinvestment in this play for multiple years to come.

Turning to the Powder River Basin, the key objective of our 2023 program is to continue to appraise and methodically refine our understanding of the Niobrara, so that we can optimize this resource for future development. With this focus, the team has made substantial progress over the last year, establishing repeatable commercial results, with three-mile laterals across a significant portion of our acreage and Converse County. Furthermore, since we are not observing any degradation in the results from 3-well spacing, we plan to test 4-well per section later this year. And lastly, we are also encouraged by the early flow rates from appraisal activity recently brought online in the northern portion of our leasehold position that could extend the Niobrara potential into Campbell County.

I will provide more updates on these tests in the coming quarters. But it has been evident that our 300,000 acre net acreage position in the Powder River Basin is providing Devon important resource catalysts for the future. Lastly, in the Anadarko Basin, production volumes grew 10% from the previous quarter, driven by the ramp up and completion activity funded by a drilling carrier from our Dow joint venture, the operational execution from this program was superb, with well costs consistently coming in below pre drill expectations and the initial flow rates from several wells exceeding 3,000 BOE per day. Today, we have only utilized approximately half of the 133 well carry agreement we have in place with Dow, we anticipate the remaining carry will provide us sufficient runway to support our current pace of activity for the next 18 to 24 months.

And we’re open to expanding the scope of partnership as we’ve successfully demonstrated in the past. For the remainder of 2023, we plan to bring on 10 new wells weighted towards year end. In summary, I’m proud of the capital efficiency results that each of our asset teams are delivering during the quarter and the strong momentum that we have built heading into the second half of ‘23. And with that, I’ll turn the call over to Jeff for the financial review. Jeff?

Jeff Ritenour: Thanks, Clay. I’ll spend my time today covering the key drivers of our second quarter financial results and provide some insights into our outlook for the rest of the year. Beginning with production. A key driver of second quarter volumes exceeding midpoint guidance was efficiency gains that compress cycle times, leading us to capture a few more days online than planned. Looking ahead. The benefits of higher completion activity from the Delaware in the first half of the year is expected to drive volumes – oil volumes higher in the upcoming third quarter and leaves us on track to meet our volume targets for the full year as well. On the capital front, we’ve invested 55% of our budget year-to-date. This waiting to the first half of the year is due to higher completion activity driven by a fourth temporary frack crew in the Delaware Basin.

With this temporary crew recently released, we expect a lower capital spinning profile as we head into the second half of the year and remain confident in our capital spending guidance range for the full year. Regional oil pricing once again remained strong with realizations near WTI benchmark levels in the second quarter. We’re also seeing strength in the oil price curve for the second half of 2023. This positive trend is providing a meaningful impact to our returns and cash flow generation capabilities with every $1 uplift in WTI, resulting in about 100 million of additional annual cash flow for the company. Despite the strength we saw in oil pricing in the second quarter, we did experience weakness in both natural gas and NGL realizations.

We do expect improved markets for gas and NGLs in the second half of the year, which should translate into better price realizations for us across the portfolio. Moving to operating expenses, our field level costs were right in line with expectations for the quarter. However, we do expect a minor uptick in per unit cost in the second half of 2023 driven by our recently executed water handling joint venture in the Delaware Basin. Our new water JV provides us significant operational flexibility to enhance scale and multiple disposal options. In addition, the JV material lowers our future midstream capital requirements in the area. Looking forward, our equity stake in the JV will provide us distributions over time, offsetting the incremental operating cost at the asset level.

We could also choose to bring forward value by monetizing this asset at some point in the future. Cutting to the bottom line, we generated $1.4 billion of operating cash flow during the quarter. Combined with the low reinvestment rates to fund our disciplined capital program, we were able to generate free cash flow for the 12th straight quarter. Furthermore, we’ve delivered these results across a variety of market conditions showcasing the durability of our business strategy. With this free cash flow, our top priority was the return of capital to our shareholders. A 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 $0.49 per share. This distribution will be paid at the end of September.

In addition to dividends, we also see great value in our equity and continue to be active buyers of our stock. During the quarter, we repurchased an additional $200 million of stock, bringing our year-to-date total to approximately $750 million. With the authorization we have in place, we remain on pace to repurchase approximately 9% of our outstanding shares by the end of next year. These opportunistic buybacks are a critically important tool for us to compound per share growth for investors over time. And to round out my prepared remarks this morning, I’d like to give a brief update on our investment-grade financial position. We exited the quarter with $3.5 billion of liquidity and a low net debt-to-EBITDA ratio of 0.7x. This leverage resides well below our mid-cycle leverage target of 1x or less.

Subsequent to quarter end, we took the next step in improving our financial position by retiring $242 million of debt at maturity. With a strong cash flow our business is generating, we will have additional opportunities to pare down our debt and maturities coming due in 2024 and 2025 as well. With that, I’ll now turn the call back to Rick for some closing comments.

Rick Muncrief: Thank you, Jeff. Good job. I would like to close out today by reiterating four key messages from our prepared remarks. Number one, our disciplined execution in the second quarter demonstrates our business is performing at a high level and building momentum as we head into the second half of the year. Number two, this positive trajectory is underpinned by better capital efficiency from higher and faster cycle times, strong well productivity and improving service costs that will contribute to our financial results over the remainder of this year and into 2024. Number three, our resource base continued to strengthen this quarter. This was evidenced by our highly commercial appraisal results in the deeper Wolfcamp and a positive redevelopment test in the Eagle Ford that adds to our conviction of resource upside across our portfolio.

And number four, with this advantaged resource base, we are deeply committed to a disciplined pursuit of per share value creation over production volume growth. Foundational to this commitment is our carefully designed cash turn framework that has the flexibility to allocate free cash flow across multiple avenues to optimize shareholder value through the cycle. And now with that, I’ll turn the call back over to Scott as we get into Q&A. Scott?

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

Q&A Session

Operator: Thank you. Our first question comes from Neil Mehta from Goldman Sachs. Neil, your line is now open.

Neil Mehta: Yes. Thanks so much. The first question is just on the production profile for the back half of the year. As you indicated, you guys are focused on value over volume. But some of the pushback we’ve done this morning has been centered around volumes being a little bit below consensus for the back half of the year. So maybe your thoughts on thoughts on whether there is some conservatism in the way that you model this out and where areas potentially that could surprise the upside? Thanks.

Clay Gaspar: Hi, Neil, thanks for the question. This is Clay. I just want to reiterate, we feel good about our full year guide certainly, with the accelerated activity, things moving a little quicker on the D&C front, that pulled a little bit of our production forward. That’s great on a per well basis, but you get a little bit of lumpiness in the productivity. So we get – we pulled some of that third quarter volume forward. So we maintain our full year guide, but we’ve always seen kind of a role as we pull back from that four frac fleet in the Delaware to the third. So nothing new, nothing unplanned, but consistent with what we’ve been showing and once again, feel real good about the full year guide.

Neil Mehta: Alright. That’s great. And then the follow-up is just, can you talk a little bit about this water handling contracts in the Delaware. There is a modest bump up in the LOE in the guide a little bit of background on what it is, and how we should think about it?

Jeff Ritenour: Yes, Neil, this is Jeff. Happy to do that. Yes, we’re excited about the flexibility and the scale that, that’s going to bring to our water handling in the basin we’re going to have multiple disposal options as opposed to what we had before. It does bring a little higher operating cost at the asset level. But as I mentioned in my prepared remarks, with the equity stake that we’ve got in the joint venture, we will be receiving distributions on a go-forward basis, which is going to more than offset that additional LOE costs that we’re going to see. So – and as I also mentioned in the prepared remarks, we also think it provides us a great opportunity with that equity position to monetize the asset at some point in the future.

So really excited about the flexibility it gives to us operationally. As Clay will attest, there is certainly a fair amount of water we got to move out in the Delaware Basin. So this additional flexibility and scale, we think, is going to be a real positive for us. I’ll also add, it certainly helps us on the capital efficiency front because it helps us to eliminate a pretty material amount of capital that we otherwise would have had to spend on water infrastructure as you look out over the next couple of years.

Neil Mehta: Alright, guys. Thanks so much.

Operator: Thank you. Our next question comes from Nitin Kumar from Mizuho. Nitin, your line is now open.

Nitin Kumar: Hi, good morning. Rick, and team, glad to speak to you. Rick, you’ve kind of mentioned a little bit of an acceleration of activity into the first half. It’s a little bit different than what you had said when you gave the guidance for the year, it does imply a little bit slower cadence of completions in the second half of 2023. And I’m just wondering, could we use that as a baseline for 2024 in terms of activity levels?

Rick Muncrief: Nitin, I’ll tell you what we like to do is we think most important thing for us is we like the consistency. As you think about quarter-over-quarter, we’ve been pretty consistent for a while on our production. And we like to look at things on an annual basis. Clay mentioned the fact that you do have some lumpiness from time to time just through acceleration. You could have working interest changes, you could have some assessment work, you do all sorts of things like that. But I think for us, the most important thing, Nitin, would be that let’s just look year-over-year, and I know that we – people like to look at things on a quarterly basis. But from my perspective, I want to watch that year-over-year profile, and let’s lean in on share repurchases and let’s make sure that we get that growth on a per share basis. And Clay, is there anything else you want to add to that?

Clay Gaspar: Yes, Rick, in your question was, should we expect that run rate. Just remember that fourth frac crew in the front half of the year we are consuming DUCs essentially in that period. Just if you look at Delaware Basin, and then when we’re running three frac crews as we will in the second half of the year, we’re essentially generating DUCs. And in a fully optimized world, we would pick up and drop that fourth spot crew to optimize. I would say in today’s world, what we’re doing is really trying to bring that crew in, get them fully up to speed, let them run through the opportunities that we have. And then put them on pause in this case, for about 6 months, we will pick them back up again in January. You’ll see capital tick up, but you’ll certainly see the production tick up as well related to that crew.

So that does exacerbate the lumpiness that we talk about. I’d love to have a straight line. But again, when you pan out and look at an annual basis like Rick talked about, you really see the consistency of our program.

Nitin Kumar: Great. Thanks for the color, Rick and Clay. I guess for my follow-up, we’ve seen some private assets change hands here in the last 3 months or so. The shape of the Delaware Basin is – has changed a little bit. You’ve previously talked about scale and the importance of that to the new business model that Devon initiated 3 years ago. So just any thoughts on the M&A market going forward? Do you see room for consolidation here? And what is the role that you think you might pay?

Rick Muncrief: Nitin, that’s a great question. I think we’ve talked about this fairly consistently. As far as consolidation, I think, a, it’s going to continue to happen. I think as you start looking across many companies’ portfolios, and we’re not one of those companies, but there is a lot of companies out there, many of the smaller companies they are going to start looking for options because they are getting light on inventory. Some of the private consolidations that we’ve seen recently that you’re referring to – many of those were companies that exhibited performance. It was really – quite honestly, it was pretty impressive in how fast they grew their production, how fast they were going through that inventory, but they also see the challenge of where they are going to go in the future.

And for companies like us, we’re going to be very, very disciplined, and we just haven’t had an appetite to really take on that steep decline rate that you would be inheriting. You have to be very, very thoughtful and it gets to be tricky. Now I will say there were some pretty creative solutions with some of those companies that had those and bringing some two and three companies altogether to make some pretty interesting transaction. But I think it just represents the creativity in our sector. I think you’re going to continue to see consolidation. I think it makes a ton of sense, and it’s going to happen for numerous reasons. And over time, you’ll continue to see companies consolidate, and there’ll be companies such as Devon, I believe, that will be the beneficiaries of those because we’re going to be very disciplined, and I think we will try to be opportunistic and make sure that we make moves that just build a stronger and stronger, more durable company.

And so – but you’re spot on. I think consolidation in our industry is going to continue.

Nitin Kumar: Great. Thanks for the answer, Rick.

Rick Muncrief: Thanks, Nitin.

Operator: Thank you. Our next question comes from Scott Gruber from Citigroup. Scott, your line is now open.

Scott Gruber: Yes. Good morning. Curious about the returns you’re seeing on the refrac wells in the Eagle Ford. How do those compare to a new well in the basin, and how does that influence, how you prosecute that program going forward?

Clay Gaspar: Yes. Thanks for the question, Scott. This is Clay. We’re really excited about the work that we’ve seen to date. We have about 30 tests we’re still learning on what’s the right wells to go in and refrac what’s the right techniques to go in and prosecute those. And so I would say for only being 30 wells and 30 refracs in we’re very encouraged about the results. We’re encouraged about the inventory that we had. I should note, in the Validus acquisition we did, we had zero refracs underwritten in the acquisition price. And now we’re seeing more material upside, both in redevelopment and in refracs. I would say on a heads-up basis, when you think about returns, the better ones certainly compete heads up with the wells that we’re drilling today.

But you really have to really think about how do you prosecute those, the right approach, and you end up getting a variety of them. So I would say it’s too early to tell on an exact quantity and the overall return, but certainly, the top half of what we’ve derisked today, we feel really good about and will certainly become more of a regular part of our investment opportunities on an annual basis.

Scott Gruber: Appreciate the color. And just an unrelated follow-up, but I did notice that the gas feed on the quarter at least versus our numbers, was largely driven by the Anadarko and by the Williston. Was anything going on in those basins that led to a gas production step up. Are you seeing the gas oil ratio of the base there step higher? Just some color on the gas production in Anadarko and Williston be great.

Clay Gaspar: Yes. Thanks for that. The Anadarko Basin certainly is our gassier option. We have a lot of running room right now. We’re more focused on the liquids-rich portion of it. But even relative to the rest of our portfolio, that’s certainly a gassier part of the mix. When we look to the wells that we’re developing in Williston, a little bit higher gas cut there as well. Very importantly, we’ve done a good job of getting that gas down the line, through the meter and sold rather than flaring. Happy to report our flaring numbers continue to be heading in the right direction around the company, especially in Williston. And that’s certainly not without challenges. I think that’s the bigger contributors to the increase in gas, getting that through the meter, getting that sold is always a very high objective, but we’re also really focused on the oil side of the equation, which is where our revenues really come from.

Scott Gruber: Appreciate the color. Thank you.

Operator: Thank you. Our next question comes from Arun Jayaram from JPMorgan. Arun, your line is now open.

Arun Jayaram: Yes. Good morning.

Rick Muncrief: Good morning, Arun.

Arun Jayaram: Good morning, Rick. I know you guys aren’t yet ready to provide more specific called soft commentary on 2024, but I did want to get maybe some of your early read on 2024 CapEx. If we look at your second half ‘23 CapEx guidance, it’s around $1.7 billion or $850 million a quarter. If we annualize that, that would be about $3.4 billion. It sounds like you would need a, call it, a partial fourth frac crew to execute your 2024 plan. So I just wanted to say if those are kind of the elements should we be thinking about CapEx in the mid, call it, $3.5 billion kind of range. But again, just wanted to get some preliminary thoughts.

Clay Gaspar: Yes. I appreciate that, Arun. I think your logic on how to get there as far as rig count, frac fleet count, I completely agree with. I’m going to hold back on giving you a number for next year. There is a lot of things going on around what’s happening in commodity price, therefore, rig count, therefore, inflation, deflation, those things have pretty material impacts, and we’re just going to hold back. But I think directionally, think of the same similar activity as a really good starting point.

Arun Jayaram: Great. And my follow-up maybe for Jeff. Jeff, I wanted to kind of zero in on the Williston Basin. This is called the third quarter in a row that we’ve seen relatively low realizations for natural gas and NGLs. So I was just wondering if you could provide what’s going on there? And is this going to be a persistent impact to you going forward?

Jeff Ritenour: Yes, Arun, this is Jeff. Yes, I appreciate the question. As Clay mentioned earlier, there, particularly in the Williston, where you’ve got some gas is obviously not the lion’s share of the production mix. But can be a real challenge, obviously, to move the gas up there given the infrastructure and the constraints that we have. I would tell you, when you look at those realizations in particular in the – excuse me, the Williston, you’re going to see some wild volatility just given the deducts that we have from a realization standpoint. And so it’s not a – it’s not going to be as clean and consistent as you would usually see in some of our other basins. I’d also point out, as you’re well aware, it’s pretty immaterial in the grand scheme of things, given the margins that we see from the oil barrels there.

Arun Jayaram: Fair enough, thanks a lot, Jeff.

Operator: Thank you. Our next question comes from Neal Dingmann from Truist. Neal, your line is now open.

Neal Dingmann: Thanks for the time. My first question, guys, is on your Delaware Basin specifically. Maybe, Clay, could you speak to what benefits that recent Wolfcamp B appraisal success might have on – I mean maybe it’s too early to say what it might have on total production. But maybe what you think the upside will that could drive in the, I don’t know, later this year or next year? And then just wondering how you view also the benefits. You’ve touched on this earlier in your comments. How you view the benefits of bringing some of those wells forward this year, not the appraisal of course, but the others.

Clay Gaspar: Yes, Neal, first question around the B. I mean, this is so important and fundamental to what we do around the assessment work. We talked about on several calls, this 10% to 20% of the dollars that aren’t directed towards the most near-term capital efficient, but it’s so important that we dig deeper out into the portfolio to de-risk these opportunities. And when we see after several reps of really understanding what that opportunity is, and they certainly jump up to the front of the line compete even with some of the best stuff we’re investing in today, it’s pretty exciting. And so it’s something we just want to share specifically in Cotton Draw, specifically in these B zones. These are really accretive and very valuable.

Now full disclosure, they are already baked into the inventory numbers that we guide to, but they are baked in on a risk standpoint. So as we de-risk them, net-net to us, there is real value creation and being able to prosecute on those. The second question was around moving the opportunities forward. So that’s just – we have 16 rigs running. They are all running just a little bit ahead of pace. The completion crews, same deal there, four frac crews for the front half of the year in the Delaware Basin, they are just running just a little bit ahead of pace. And so that fourth crew that we toggle on and off originally was slated to run through October. And then we pull it back to September than August. We finally were able to release that in July and accomplish everything that we needed to accomplish.

So you can imagine the well cost savings and the value creation on a per well basis. Now it kind of monkeys with our quarterly numbers a little bit, as you can see. But overall, we’re always trying to pull that value forward. We’re thinking about per well full cycle cost, how do we continue to drive that? And then how does it manifest to the bottom line of the company.

Neal Dingmann: That makes sense. And maybe the last one for Jeff, just on capital allocation, just how aggressively Jeff, do you all think about going forward, do you all plan to target net debt while combining this with your strong shareholder return program?

Jeff Ritenour: Yes. I appreciate the question. I think going forward, you are going to see our – as our framework has been pretty consistent from day one, as Rick mentioned in his opening remarks, you shouldn’t expect a material change in that approach. We are going to be pretty balanced. As you saw this year-to-date, between the variable dividend and the stock buyback, it’s been about 50-50, which to me is a great example of how well our framework is working last year when you had much higher prices and significant free cash flow generation. We leaned in on the variable dividends. And this year, when you have seen that pull back, you have seen much more balance from us with the stock buybacks as well. Going forward, where we are from a cash balance and a framework standpoint, as we generate excess free cash flow here in the back half of the year given the lower capital spend we expect, and the higher oil prices that we are projecting in the back half of this year, we should generate significant free cash flow, we are going to look to build our cash balance back.

And then with the remainder of the cash, we are going to focus on, obviously, the variable and the stock buybacks on an opportunistic basis.

Neal Dingmann: Very good. Thank you.

Operator: Thank you. We have our next question comes from Doug Leggate from Bank of America. Doug, your line is now open.

Doug Leggate: I have two if you don’t mind. One is on mix, and one is on portfolio capital intensity. And I guess it’s that we have seen this trend obviously across a number of your peers. But if you look at the oil mix in your production. It’s obviously been up and down a little bit over the last couple of years, but it seems to have dropped now below 50%. I am just wondering when you think about how you are allocating capital between your different operating areas, particularly, I guess Anadarko versus Permian. How do you anticipate as you optimize your spend that, that oil mix is going to trend? I have got a follow-up, please.

Jeff Ritenour: Yes. Doug, this is Jeff. I would say we view that the mix of the oil to be pretty consistent on a year-over-year basis. We are really focused on rate of return and the returns that we generate in our play. We are agnostic, frankly to oil or gas. But as we all know, certainly, oil is the higher-margin product today, and our focus has been, particularly in the Delaware. So, with the Dow JV that we have in the Anadarko Basin, that obviously reduces those returns and helps from a capital efficiency standpoint and makes that activity pretty competitive with our broader portfolio. But we – I think we would all tell you, and it’s not going to be a surprise to anybody on the call that the Delaware without doubt is our most capital-efficient asset today, it’s oil-weighted. That’s where the bulk of our margins come from. And as we move forward into 2024 and beyond, we would expect it to capture the lion’s share of our capital investment.

Doug Leggate: Okay. I guess we will take another look at that. But my follow-up, Jeff is, look, I realize that inflation and cost and everything else is a well-trodden path. Everyone understands what’s going on there, what has gone on there. But I want to share an observation with you just to get your opinion on this and see what you think. When I look at your peers, obviously, one of your large peers reported this morning that the capital intensity simplistically on a per BOE basis is up about 30%. U.S. is up about 80%. For example, if I take your spend in the first half of last year, it was about $10 a BOE. First half of this year, it’s about $17 a BOE and production is obviously up small. So, I am just wondering if you can address that and tell us what you think is going on? Is there capital in there that is transitory, for example, in the infrastructure you talked about or what else should we be looking at to try and understand what’s changed there?

Jeff Ritenour: Yes. Doug, I would say, as you know, it’s a mix of things. Without a doubt, one of the things that we have talked about a lot is the inflation that hit us and that certainly started in the back half of last year and worked its way into this year. That’s a big driver of that. The timing of our contracts and the roll-off of our contract structure as it relates to all of the different cost categories, I think has also disproportionately hit us relative to our peers. Said another way, I thought our teams did a great job of protecting us from the inflation in the very early part of the cycle. So, think about the fall of last year and the early part of this year. And now as we worked our way through 2023, a lot of those contracts have rolled off into a higher price environment from an inflation standpoint.

And so you have seen some of the capital efficiency for our asset base relative to some others certainly change. Obviously, mix is a big driver of that. The shifts that we made with the acquisitions in Validus and RimRock, you are moving away from a more capital-efficient asset in the Delaware from a mix standpoint to really great assets, really great returns in the Bakken and the Eagle Ford. But as I mentioned in my response to the previous question, they are certainly not as capital efficient as what we see in the Delaware. So, you put all that together, and I think that’s what you are seeing really driving that capital efficiency rate of change relative to some of our peers. I will say, though, when you step back and you look at that capital efficiency on an absolute basis, company versus company, we feel really good about where we sit, and we look really, really competitive against the top-tier companies in the space.

That rate of change as you pointed out has just been pretty material and have been a challenge on a relative basis as you all screen for capital efficiency. But when we look at the capital efficiency on an absolute basis, we still feel really good about where we sit. And we expect that to improve as we work our way into the future for all the reasons you mentioned earlier, which is we do expect to see some deflation as we work our way through the back half of this year and into next year. And as Clay mentioned earlier, the mix of our asset base and the things we are focused on, we think that only is going to add to our productivity moving forward.

Doug Leggate: Okay. Thanks for the answer, Jeff. Appreciate it.

Operator: Thank you. Our next question comes from Matthew Portillo from TPH. Matthew, your line is now open.

Matthew Portillo: Good morning all. Clay, maybe a question for you to start off on the Bakken. I know that’s an asset that has faced some technical challenges to start the year. Could you impact some of the headwinds a bit more that you faced in the first half and maybe a little bit more around the completion design change that you guys have made that may start to show some improvement in the well results in the back half and heading into 2024?

Clay Gaspar: Happy to do it, Matt. Thanks for the question. As I think about the Williston, it is certainly maybe the most mature of all the oil resource plays. We are learning things for the first time what these late innings really look like. Certainly, with the RimRock acquisition, bringing those wells in, we faced some challenges really from a surface standpoint, but also from a relatively surface standpoint, and I will talk about both. From a subsurface standpoint, one of the challenges we faced, specifically with some of the wells we acquired is the nature of the depletion. These crosscut wells are really unique. And so we have seen wells we have drilled through essentially have a depletion and then essentially verge pressure and then back to depletion throughout the lateral.

Producing those – completing those and producing those have been a relatively unique challenge. We haven’t seen anywhere else. We have gotten some solution, I have talked about earlier. I think we are doing really well on getting those wells producing consistently, getting them unloaded and allowing the proppant to stay in place, which is fundamentally important to be able to producing the wells. More on the surface side, once you get that proppant in place, then you don’t have the challenges of artificial lift. You don’t have the sand flowing back to surface and adding additional complications. What we really faced in the first quarter was some of these operational challenges and then still in a very tight workover rig environment, reaching for that workover rig, having to stand in line or the opportunity cost of pulling it off of something else we were trying to do has been pretty uniquely challenging.

I think we have gotten a good recipe for the wells going forward. A lot of our inventory that we are able to go back to now will not have some of these same challenges. It’s more run of the mill, what we have been dealing with in Williston for the last several years and really delivering some really good well results. So yes, the first quarter was challenging from an operational standpoint, especially in the first quarter, compounded by weather. I feel good about the direction we are headed, the response we have had from the team, and the outlook going forward.

Matthew Portillo: Perfect. And then just as a follow-up, in your prepared remarks, you mentioned seeing quite a bit of success in the Anadarko Basin and the potential for a further expansion of the partnership. Just curious, is that something that you may pursue with Dow, or are you looking at bringing in potentially other partners to continue to progress the asset from a development standpoint?

Clay Gaspar: We love – we cherish our partnerships, and we love it when it’s a mutual win-win. Dow has been very pleased with this partnership. We have as well. It’s allowed the Anadarko Basin to compete in our pretty rigorous portfolio. And so expanding that, certainly, Dow has a very good knowledge of the basin, it would be the easiest to pursue with them. Certainly, look, we are objective. We have other partnerships around the company, but it’s something we are regularly talking about with Dow, how would this work for them, how would this work for us. We haven’t made any decisions on that, but just thought I would mention, we have an additional runway beyond the current scope that we may end up pursuing at some point.

Matthew Portillo: Thank you.

Operator: Thank you, Matthew. We have our next question comes from Scott Hanold from RBC. Scott, your line is now open.

Scott Hanold: Yes. Thanks. I am just wondering if you have had some thoughts on just the overall maturation and depth of your inventory. It appears with you all that there is a little bit more exploration and refrac and other kind of opportunity. Does that point to the maturity of some of the assets? And is there a little reason more to do more kind of exploration and development of that sort, or just give us a sense of like when you think about like primary drilling of economics you have today, like how much of a runway do you have?

Rick Muncrief: Hey Scott, it’s Rick. We feel really good about our runway, but we also are compelled to continue to explore, to continue to assess what we already own. You have heard several comments, commentary around consolidation opportunities. I think it’s incumbent upon this management team to first, let’s understand what the opportunities we already have in hand. You have heard Clay talk about how we had – in the Wolfcamp B, we feel really, really good about some resource potential there. We had it in a risk basis, and you go out and you execute on those and you find out that they really are good. And the implication is that not only the offsets of where we are at, but when you think about a 400,000-acre position that we possess in the Delaware, and you can continue to do these and these assessment activities.

And quite honestly, you either meet or exceed what your expectations are. That’s a good thing. That’s better than good. That’s a great thing, because that adds to your risk or your un-risk – excuse me, your risk inventory that you feel really good. When I say that, that’s inventory you are pulling off the shale and executing on and with phenomenal returns. And so whether it’s in the Delaware, whether it’s these opportunities that we have in the Eagle Ford, which we are really bullish on, which is the opportunities we see in the Bakken, which we continue to see some nice opportunities there. We feel really good about it. But I think it’s incumbent upon this team to continue to assess what our current acreage position is as we compare and contrast executing on that, holding what we have versus going out and buying more, consolidating more.

So, just – it’s real fundamental to our business.

Scott Hanold: Yes. I mean – and that’s good to hear. And I think the question is a lot on sort of the capital efficiency trend as you move from a very high core prolific Delaware Basin to some of these other zones or even to some of these other players like the Anadarko and Eagle Ford and Williston or PRB, right? So, it’s more about that capital efficiency trend relative to kind of the best stuff you have already drilled?

Rick Muncrief: Right. I think that’s what you are going to see. I think you are seeing maturation in a lot of these basins. And if you just think about whether it’s – you have seen it in the Midland Basin. We are not in the Midland Basin, but you have seen that for several years where every year until you start bringing new resource on, you are going to be continuing to evolve and people tend to go to their highest returns. What – you have seen it in the Bakken. We have seen it in the Eagle Ford. But I can tell you there is many of these basins. We are excited about the potential that we see with restimulation and some tighter spacing. In some cases, we up space in the other areas. We just learned more about the resources we have.

But that’s been the history of our business over the last 100 years is plays and basins will mature over time until there is either a change in technology, new intervals are found. And so I think you are just – you are seeing that play out in real time. We are continuing to – but we are excited about what we are seeing. So, hopefully, that’s coming across in our – not only in our prepared remarks, but some of our answers that whether it’s restimulation down in the Eagle Ford, whether it’s what we are seeing the assessment work in the Delaware and other places Powder, Anadarko, we are just really excited about what we have.

Scott Hanold: Okay. I appreciate the added color. And just one quickly on the fixed dividend, you have spend a little bit time, Jeff, on buybacks and variables. But remind us of your thoughts on the fixed dividend, what – where you want that to be? I think it’s about 1.5% or something to that effect. Do you feel good about that, or would you like to see it stronger relative to the S&P or to some of your, obviously, E&P peers?

Jeff Ritenour: Yes. No, absolutely. I am glad you asked the question. We are absolutely focused on growing the fixed dividend as we work into the future. And so you should expect us on a year-over-year basis to lean in and grow the fixed dividend as we get more and more confident, obviously, in our base game plan and our framework. It’s – yes, I certainly should have mentioned it earlier. It’s the priority one as it relates to our cash return framework, and it only falls behind, obviously, the financial strength and the balance sheet. So, absolutely expect to see us grow that into the future.

Scott Hanold: Thanks.

Operator: Thank you, Scott. We have our next question comes from Paul Cheng from Scotiabank. Paul, your line is now open.

Paul Cheng: Thank you. Good morning. Two questions, please. First, I think Clay, you mentioned that Bakken is the most mature, and which certainly is the case. And you talked about the refrac and redevelopment opportunity in Eagle, can you talk about within your portfolio, have you already looked at what is the refrac and redevelopment opportunity in Bakken and how long do you think you may be able to hold the current production spread. The same question, going back into the Eagle Ford, I know it’s still early, but for refrac and redevelopment, what kind of WTI and Henry Hub gas price minimum you need in order for those to work? Thank you.

Clay Gaspar: Yes. So, I will tackle those. Starting with the Williston, it’s a very different reservoir rock than the Eagle Ford. The Eagle Ford is very notoriously tight, low permeability, which is a challenge in trying to initially develop. What we are finding is there are some benefits in redevelopment being able to space in wells later in life and not having some of the challenges that we see in other basins. We are not going to be able to do that same kind of model in many other basins because it’s fairly unique to the Eagle Ford. When it comes to refracs, it’s a little bit different scenario. Williston being on the more mature and also having a fair amount of the development early in the industry’s understanding of how best to complete these wells.

There are some really inferior completions, and so the opportunity there is a little bit different. It’s not from a reservoir standpoint, it’s more from a completion standpoint, how do we go in and restimulate some of these wells that were massively under-stimulated. So, therein lies a different opportunity there. The Eagle Ford, you asked about kind of breakeven costs for the refracs, I don’t have a very good number for that. I would say, in the top half of the opportunities that we are looking at, many of those are very competitive with what we are drilling today, which is pretty – a very, very solid return. So, I would put it in that bucket. There is still a lot of work to do on refining how do we figure out where is the line and certainly commodity price will play a role in how many of these refracs and potentially even trifracs, you come back again at a later date.

Those opportunities will certainly be commodity price dependent.

Rick Muncrief: Paul, it’s Rick. I would just say that when I think about those restem opportunities down the Eagle Ford. In my mind, in a $50 world, as long as you are north of $50 and a $3 Henry Hub, you are going to have some pretty good returns. We are pleased with that. One of the things I will add, the previous question we had was around some of the assessment work, just – everybody needs to recall, we are only doing a small percentage of our capital budget with assessment work. It’s not like we are really leaning in on that. We do think it’s important to allocate a certain amount of capital and really excited about what it holds for us. That being said, I know at a time when people are hyper focused on capital efficiency, that’s fair. It really is. But we also need to think about the future. And when I say the future, it’s not next quarter, it’s the next 5 years, 10 years, 15 years, 20 years.

Paul Cheng: Thank you.

Scott Coody: Alright. It looks like we are at the top of the hour. I appreciate everyone’s interest in Devon today. And if you have any further questions, please don’t hesitate to reach out to the Investor Relations team at any time. Have a good day everyone.

Operator: Thank you. Ladies and gentlemen, this concludes today’s call. Thank you for joining. You may now disconnect your lines.