Jeffrey Ritenour:

Thanks, Clay.

Arun Jayaram:

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?

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.

Neil Mehta:

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?

Jeffrey Ritenour:

Yes. You bet, Neil. This is Jeff again. Great question and certainly something we've been talking a lot about internally and externally.

Operator:

Our next question comes from Nitin Kumar with Mizuho.

Clay Gaspar:

Yes. Thanks for the question. And the clarification, both Rick and I covered this in our prepared remarks. 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 3 big contributions to the outperformance. Number 1 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 them in. We had a couple of more days online here and there. Cumulatively, that adds up.

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?

Operator:

We now turn to Scott Gruber with Citi.

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 4 frac crews, that we are consuming some of the pent-up DUCs. And then we're running 3 frac crews, our production is rolling over a bit, but we're also building a little bit of a DUC inventory. And so as I expect, and we've guided to first quarter is in the bag. Second quarter, we've guided to a little bit of additional growth. Third and fourth, we'll see a little bit of a rollover on the back of lower completions activity and then building those DUCs, we'll be ready to get back to work with a fourth frac crew either late in the year or probably more likely early in '25.

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 near year capital number.

Operator:

Our next question comes from Neal Dingmann with Truist.

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% 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.

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?

Roger Read:

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 more back to shareholders or has been asked a little bit earlier, something on the acquisition front, like build a little cash in front of need?

Clay Gaspar:

Between those 2, 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.

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 to head 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.

Operator:

We now turn to Kevin MacCurdy with Pickering Energy Partners.

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.

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?

Charles Meade:

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 60% well performance with 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?

Clay Gaspar:

I think that's a great question, and I'll take a little bit of that -- I'll take some of that bait 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.

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.

Scott Hanold:

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:

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.

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 3 wells that have produced the B, the first 2 were just kind of so-so, and so our expectations were pretty moderate.

Matthew Portillo:

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 2 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?

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 just 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 perspective?

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.

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 past year and our outlook for 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 our 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.

Clay Gaspar:

Thank you, Rick and good morning everyone. The Devon team did a really good job of rounding out 2023 by exceeding our operational targets for the fourth quarter. These positive results were driven by three key factors

Rick Muncrief:

Thank you, Jeff. So to wrap up our prepared remarks, I want to reinforce a few key messages. Number one, Devon is a great company that has created a tremendous amount of value for shareholders since we unveiled our industry-first cash return strategy announced in 2020. Since that time, we’ve deployed $13 billion to dividends, buybacks, debt reduction and accretive acquisitions. I’m extremely proud of this accomplishment, but we’re just getting started. . 2024 is setting up to be another wonderful year for Devon. By incorporating learning’s from the past year and refining our capital allocation, we expect to deliver a step change improvement in capital efficiency this year. This improved capital efficiency is anchored by our assets in the Delaware Basin, where we expect to deliver the powerful combination of improved well productivity for much lower capital cost. Our long-duration resource base underpinned by the Delaware is one of the deepest of any company out there. The resource quality provides us an advantaged platform to drive attractive per share growth and outsized cash returns for many years to come. And with that, I’ll turn the call back over to Scott, and let’s have some Q&A.

Operator:

Perfect. Thank you. [Operator Instructions] We do have our first question registered comes from Neil Mehta from Goldman Sachs. Neil, your line is now open.

Rick Muncrief:

Neil, that’s a good question. We have expressed our frustration, I think, in the market really – we really traded down on some of our variances we saw last year in our production volumes. But even though they were minor from a volumetric standpoint, they weren’t from a stock performance standpoint. So I think the setup is really good for investors as we look forward. So it is going to be, I believe, point of inflection for us as we’ve mentioned. Really bullish about our performance, the team has done a wonderful job, getting us through some tough weather. We’ve seen some increased productivity. I think Clay went through the assets really well, and we’re seeing nice growth on the oil side coming out of this first quarter as we enter second, third, fourth quarters of this year. And I’ll also say, Neil, I feel really good about the next several years on our ability to keep our crude volumes where they’re at. I think that it’s – we’re still early. We still are not getting what I think is a strong, strong signal for demand. But when that call comes, I think we’ll be ready to step up for it. But we really feel good about the trends we’re seeing.

Clay Gaspar:

Yes. Thanks for the question, Neil. This is one of the frustrating things about a publicly traded company. We get to see what’s coming. We get to see what’s happening well before the market does. And so where I can see the improvement internally in the well productivity from the first half of last year to the second half of last year, those numbers are just starting to hit the public markets and through the public sources. And so I think that’s pretty evident for those that are paying attention that this is not first quarter ‘24, we decided to turn on the production. This is an evolution. We wanted to make some really thoughtful investments in the future of the company. We did that. The market, I believe, responded pretty vigorously to that. We’ve since made some changes in the planning, the well delivery, the well performance is really significantly taken an uptick. As I mentioned, even late last year, you see some of that coming through the public sources. We’re going to – it’s really going to manifest in 2024 and as Rick mentioned, we’re just off to a really good start, even recovering from a pretty severe storm that we saw somewhere 1% to 2% impact. We always bake in winter weather, but an event like that was pretty out of the norm. The productivity of the wells, the performance we’ve been able to overcome that, and we feel really good about delivering – being able to deliver the ‘24 full year numbers.

Rick Muncrief:

Thanks, Neil.

Arun Jayaram:

Yes. Good morning, gentlemen. Rick and Clay, you’ve highlighted your expectations to deliver up to 10% well productivity gains in the Delaware Basin. I was wondering if you could maybe help us provide more details on what is driving that? It sounds like there’s going to be some high grading for Monument Draw to Southeast of Mexico. But I was wondering if you could talk a little bit about what’s driving that and – and if completion optimization is also a driver of better year-over-year productivity?

Arun Jayaram:

Great follow-up, Rick, Devon, as you know, has been linked to a few M&A deals in the financial press. I was wondering if you could just comment on where you sit today in terms of your A&D strategy, and how you gain some of the inorganic opportunities versus, as Jeff mentioned, the ability to buy back your stock at a 9% kind of free cash flow yield today?

Arun Jayaram:

Thanks, guys.

Operator:

Our next question comes from Nitin Kumar from Mizuho. Nitin, your line is now open.

Jeff Ritenour:

Nitin, this is Jeff. Keep in mind that there is some variance in the timing of the variable dividend payout, right? So when we announced it, it actually gets paid in the subsequent quarter. So maybe that’s what you’re alluding to as it relates to the mix. But with our framework going forward, we’re going to simply each quarter, focus on delivering about 70% of our free cash flow back to shareholders in the form of that fixed dividend, which, obviously, we grew at 10% here on a year-over-year basis. That’s the first and foremost going to be a priority for us, and we’re going to look to continue to grow that on an annual basis going forward. Then beyond that, we’re absolutely biased towards leaning in on the share repo here in the near-term. And frankly, the variable dividend will fall out of the back of that based on that 70% threshold that I hit on earlier. So we’re going to continue to expect to have a higher mix of buyback going forward. And that’s going to be our priority as we walk it through this year.

Clay Gaspar:

Nitin, it really goes down – goes back to just the core operating team. These are highly talented, highly motivated individuals that are absolutely trying to do the right thing ultimately for the shareholders they work for. Now I will remind you, this is the same team working just as hard with just as much creativity this year as they were last year. What we found is we really needed to focus. We underestimated what a slight change in capital efficiency during the first half of ‘23, meant to investors. I think that was way over extrapolated into us running out of inventory, not being able to do this anymore. We lost our minds, all that good fund. And what we showed is like hang on a second. We still have the capabilities. We’ve got some really impressive inventory, some great quality. And importantly, these are hard-working impressive people that continue to find a way to do it better each quarter. And this is so many things below the radar that don’t always show up in the [indiscernible] data, don’t show up in the financials. I can tell you, we’re winning on lots and lots of fronts and there’s more that to come. So really excited about the go forward. I think we’ve got some good transparency in our slides on quantity of resource, quality of resource. I expect in ‘24 that we will regain a little bit of public mojo, but that, to me, is just – it’s a little overdue. So looking forward to sharing that win with the team.

Rick Muncrief:

Thanks, Nitin.

Unidentified Analyst:

Hey, good morning, guys. This is actually [indiscernible] on for Doug. So, thanks for taking me on. For my first question, I want to go back to the buyback, just to follow-up. I want to understand the motivations behind the strategy for ‘24. Shifting capital back to the Delaware and the margin is obviously an efficiency shift and that makes sense, but in tandem, you’re also leading back into the buyback and that looks rather intentional. So can you talk about why you see the buyback as a preferred allocation today? And why has that changed over the past several months?

Clay Gaspar:

And if I could, I just want to clarify – I’m sorry, I just want to add one comment on that prior question. I think it’s a common misconception the way we lay the numbers out that we are leaning in or that we’re increasing capital to the Delaware somehow accelerating, that’s not really the case. We are the same rig count, same level of activity. The capital is actually coming down, not just in the total company, but in Delaware, but where we’re seeing the 10% inflection from the company is really a reduction in some of the other areas. So proportionately, Delaware is moving up, but on an absolute basis, we’re not consuming that inventory any faster than we had in ‘23 or years before.

Clay Gaspar:

Was the question [indiscernible].

Clay Gaspar:

Can we do it multiple years? I’m just making sure I understand the question.

Clay Gaspar:

Okay. Alright, thank you for that. Sorry. The acoustics in here weren’t quite right. Sorry about that. Yes, I think in pulling back the activity, for example, in the Williston Basin, that prolongs that basin’s opportunity to continue to deliver free cash flow and offset some of that fall in production with some really healthy wells. What we found is we were pushing a little too quickly, a little too much capital to that asset by having the multiple basins that we do, having our franchise asset in the Delaware Basin. It allows us to take a little bit of pressure off that team, allows them to really make sure that all the ducks are in a row ready for that next pad. And then selectively, we’re going to fund those. And as you saw with the bull news that I talked about on the call, these are phenomenal. These are awesome returns, and we’ve got more of that to come.

Clay Gaspar:

You bet.

Neal Dingmann:

Good morning, guys. Thanks for the time. Clay, first question for you. It’s on your Delaware infrastructure and takeaway. I’m just wondering, after adding so much [indiscernible] where you talked about adding so much processing, gathering, compression, water – just wondering now, are you all able to handle the continued notable upside that’s going to come with the development plan or will there be a continued build-out?

Neal Dingmann:

Yes, it makes sense. And then my second is just on the Eagle Ford, specifically. Can you give details – I think you talked about 85 to 95 well plan, I’m just wanted to focus here be on existing key areas like you’re doing in the model and just maybe talk about any improvements we should think about specifically in this area?

Neal Dingmann:

Great to hear. Thank you.

Operator:

Our next question comes from Kevin MacCurdy from Pickering Energy Partners. Kevin, your line is now open.

Clay Gaspar:

Yes. It’s interesting, Kevin. One of the first thing that comes to mind for me is the efficiency that I talked about in a couple of my slides, you guys know this very well. We’ve been at this game for quite a while. Sometimes that efficiency can pull more activity into the calendar year. Look, this is not our first rodeo. This is February. We’re already watching that for the full year. We’re committed to this range. But if I had to think of what could cause us to kind of float to the upside, it’s probably that kind of work where you’re seeing more opportunities bring some of that activity from ‘25 into ‘24. I think on the downside, there’s – we’re early in the year. I think the supply chain deflation opportunities are still – we’ve got a 5% year-over-year kind of baked in. I feel good about that. I feel very confident we’re going to be able to deliver that. As the year plays out, we really need to see where that changes over time. My current crystal ball doesn’t see a lot of inflation, but there’s certainly deflation opportunities in that number, and that potentially could allow us to float down to the lower end of that range.

Rick Muncrief:

Hi, Kevin, this is Rick. One of the things that I’ve been really proud of over the last 12 to 18 months is coming on the heels of the Validus acquisition, what we have been able to learn at a solid acreage. It’s – I would say it is second, certainly to our Black Hawk acreage. But the thing about it that we need to remind investors of and analyst is that on the Black Hawk acreage, it’s a 50-50 joint venture with BPX. BPX operates the drilling and the completion of that. And what we felt it was really from a – not only a productivity increase, but also just a strategic perspective, we thought it was imperative that we had an asset that we owned that we did the drilling that we did the completions on. The 5-day well that Clay referenced a while ago, I can tell you that absolutely exceeded anything that we had in our Validus development plan. So when I look at that, look, now we’re having some very, very meaningful discussions with our joint venture partner there. And they’re very constructive, and I think it’s going to lead to even better performance over time in the Eagle Ford. I’m really pleased with what we’re seeing with the refrac program. It’s going to continue to drive some – I think, some long-term sustainability down there that a lot of people, I think, are underestimating. So I’ll turn it over to Clay to add any additional color, but the Eagle Ford is an area I can tell you that we’re very excited about.

Operator:

Our next question comes from Scott Gruber from Citigroup. Scott, your line is now open.

Clay Gaspar:

Scott, it’s pretty consistent year-over-year. We are always trying to drill longer laterals. It’s kind of the opportunity set in front of us. We are always – we feel very confident in our ability to deliver three-mile laterals from a productivity, from an operational standpoint. The land mix doesn’t always allow for that. So, we are going to be north of two miles, but not too much north, and it will be fairly consistent year-over-year.

Clay Gaspar:

Scott, I think it’s really the well mix. We have got some wells coming on, the Williston wells are exceptionally high oil cut. We continue to bring those in. I think that’s just working in our favor in that regard.

Clay Gaspar:

Thanks sir.

Scott Hanold:

Yes. Thanks. If I can delve into the infrastructure a little bit more. On Page 13, you obviously bucket three areas that you are focused on in terms of building support for the 2024 plan. As you think about the Permian development over the next 2 years, 3 years, 4 years, like which area really are you focused most primarily on to make sure you are executing on the plan? Like where do you see the risk of the biggest constraint, I guess is the question?

Scott Hanold:

Okay. Thanks for that. And as my follow-up, it’s going to be on M&A. And I was hoping to get a deeper sense of how you think about M&A. And it’s really two parts. One, first, if you can comment on some of the recent deals that have been out there, if you all participated and really what was the gives and takes of why – if you did, why Devon didn’t went out. And then number two, you all mentioned obviously, you are a multi-basin player, but like when you think about like does Devon have the scale right now that it would like? And if you were to add, would it be really most a Permian thing, or are other of those basins open to more significant M&A for Devon?

Scott Hanold:

And regionally, is there an area you focus a little bit more time on? Is it Permian, Bakken, Eagle Ford, like are all areas of focus?

Scott Hanold:

Thanks for the color.

Operator:

Our next question comes from Charles Meade from Johnson Rice. Charles, you may proceed with your question.

Rick Muncrief:

Yes. I am going to let Clay answer the balance of that. But just in real time, just yesterday, I was talking to our – one of our completion managers down there and we are picking up the fourth crew as we mentioned, but the three that have been out there, the – it’s incredible, Charles, on the efficiencies and what we are doing out there. The number of stages and it’s interesting, there is – it’s healthy competition between the team members and certain of the companies that are involved with it and we are actively comparing and contrasting ways that we can get better and better. And at the end of the day, we want to make sure that we do this very, very safely and efficiently. And so we are constantly changing every pad has its unique characteristics. But I can tell you that more and more, we just see these efficiencies that are just incredible. And things that just 12 months ago, we knew that you would see some efficiencies, but we are exceeding some expectations. Clay, why don’t you maybe some follow-up Charles.

Charles Meade:

Got it. And then, Clay, I want to go back to your prepared comments, you were talking about – I think I heard you talk about some additional landing zones in the Wolfcamp B, and I am not sure I kind of – I caught it all when you were talking about it. So, I was wondering if you could elaborate a bit on that and perhaps including your answer, an indication, is this something that you are going to be – that you are working into the ‘24 program, or is this an out-year sort of project?

Charles Meade:

Thanks for added detail.

Operator:

[Operator Instructions] And our next question comes from David Deckelbaum from Cowen. David, your line is now open.

Clay Gaspar:

I think it’s – I would put it in the same category as Devon. We are a low growth kind of zero to 5%. Delaware will play a certain role. Some quarters, some years, it’s going to be a little bit of a tick up. Others, it’s going to be relatively flat. But I wouldn’t think of it as a standout growth asset. We are really pleased with the year-over-year performance. As I mentioned, it did grow. We also were able to build a few extra DUCs during the course of the second half of last year that we were able to capture the benefit of in the first half of this year. So, there is kind of that going on in the background. But I wouldn’t say it’s materially out of step with overall Devon or with the other basins.

David Deckelbaum:

Thanks Rick and Clay. And maybe just Rick, one of the, I guess other parts of the capital budget that continues to grow every year, albeit still small as carbon capital. In a world where you are trying to enhance returns of capital to shareholders, could you kind of contextualize how you see that spend generating returns for Devon as a whole and why that’s sort of seeing a larger piece of the pie this year, albeit small?

David Deckelbaum:

And just for my own edification, is that capital being earmarked for projects that would allow you to prolong production on some of these wells such as increasing methane capture, or is this capital associated were tied to plugging and abandoning some of those wells that would be more regulatory headaches?

David Deckelbaum:

Thanks guys.

Operator:

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

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 our results for the quarter and updated outlook. 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.

Clay Gaspar:

Thank you, Rick and good morning, everyone. For today, I plan to focus my comments on our Delaware Basin operations as well as outlining the actions we plan to take to sharpen our capital allocation and drive efficiencies in our business over the next year. Let's begin on Slide 15 with an overview of our Delaware Basin activity, which accounts for roughly 60% of our capital spending for this year. With this level of investment during the quarter, we ran a consistent program of 16 rigs and brought on 59 new wells. Well productivity was very strong with 30-day rates averaging 3,000 Boe per day and improved average productivity combined with the benefits of elevated completion activity in the first half of the year drove another quarter of production growth from our franchise asset. That said, our growth rate in the quarter was held back by a few wind and lightning storms that impacted power for our facilities as well as our third-party infrastructure. These storms stranded a few thousand barrels per day during the quarter. The infrastructure and the wells are back online, and we don't see any negative impacts on the ultimate recovery of these wells. On Slide 16, you can see our impressive well productivity in the Delaware Basin during the quarter. It was highlighted by three important projects. On the far left of the slide, Devon's top result for the quarter was the Bora Bora project. Developing the Upper Wolfcamp at our Todd area, with 30-day rates from Bora Bora, averaging 4,600 Boes per well, with the cost coming in under budget, these returns are expected to be well into the triple digits for this project. Another noteworthy project was our CBR 17 development in Texas, where 30-day production rates averaged 4,100 Boe per day per well. The CBR 17 results were enabled by a 3,000-acre trade completed about a year ago that I highlighted on the previous call. This key trade, which unlocked our ability to pursue extended reach laterals by extending our laterals to two miles for this project, we added several million dollars of net present value in this project alone. On the right, another key result for us was the Haflinger project, where we co-developed multiple zones in the Wolfcamp A and B. While rates were restricted due to infrastructure, recoveries on this are on track to reach 1.5 million Boe per day per well – excuse me, per well. With solid returns from our Wolfcamp B appraisal today, we now plan on bringing forward of this opportunity by co-developing the Upper Wolfcamp where possible in the future activity. Looking forward to the project level details, Slide 17 provides a nice visual of the well productivity we achieved in the Delaware Basin during the third quarter. On the left, as I touched on earlier, 30-day average rates for the Delaware wells we brought online reached 3,000 Boe per day. These high-impact wells exhibited a 20%-plus improvement from the first half of 2023, reaching the highest quarterly level in more than a year. This performance is great to see, given our well productivity over the past year has been held back slightly by elevated appraisal requirements and infrastructure constraints. The 2023 infrastructure constraints resulted in a shifting a portion of our capital to less prolific areas in the basin and at times, constrained peak rates across a subset of our new wells. As you can see on the right-hand side of the slide, we also made progress improving our cycle times across our drilling and completions operations in the basin. Third quarter results were highlighted by our completion space exceeding 2,000 feet per day for the fifth consecutive quarter, and we drilled several pacesetting wells that achieved spud rig release times of less than 15 days. With the momentum we've established, we believe we can build upon these results and capture further efficiencies and as we head into 2024. Turning to Slide 18, as Rick touched on earlier, we're excited about the plan we have in place to drive improved well productivity in the Delaware with our 2024 plan. With the ongoing industry build-out of infrastructure in the form of electrification, compression, localized processing and downstream takeaway, we plan to allocate approximately 70% of our capital to the Delaware Basin and specifically to the core of New Mexico, while we can optimize the remaining activity across our acreage in Texas. As you can see on the chart on the left, by refining our focus on high-impact Wolfcamp zones in the core of the play with less appraisal requirements, we expect Delaware productivity to improve by 10% in 2024. Looking beyond 2024, we have a long runway of high value inventory in the Delaware that positions Devon to deliver highly competitive results for the foreseeable future. As we've discussed in the past, we've identified more than a decade of risked inventory across the Delaware and we expect to steadily replenish this inventory over time as we successfully characterized the many upside opportunities across this back play resource. In addition to our internal estimates, there are plenty of third-party services that can provide in-depth evaluation of our resource base. A great example of this on Slide 19 and that references the recent Enverus Permian inventory report. While I won't go through all of the details on the slide, there are three key takeaways you should have. First, one of the – we have one of the largest remaining inventories of any operator in the Delaware. Second, the quality of this inventory is excellent with returns exceeding a PV-10 breakeven at $40 WTI. And third, we possess significant upside to our risk resource from many known geological viable zones that have yet to be fully characterized. So in summary, with the Delaware accounting for roughly 60% of Devon's total risk resource, we're going to be delivering some excellent results for quite some time. And with that, I'll turn the call to Jeff for a financial review. Jeff?

Rick Muncrief:

Thank you, Jeff. I would like to close today by reiterating a few key messages from our prepared remarks. Number one, we plan to incorporate our learnings from the past year, tighten a few things up and refine our capital allocation in 2024 to deliver a step-change improvement in capital efficiency. Number two; this improved capital efficiency is anchored by our franchise asset in the Delaware Basin, where we expect well productivity to improve by up to 10% year-over-year. Number three, with our long-duration resource base, we have a depth of inventory to deliver sustainable results through the cycle. And number four, we are deeply committed to a disciplined pursuit of per share value creation and our carefully designed cash term framework that has the flexibility to allocate free cash flow across multiple avenues to optimize shareholder value. We've demonstrated that and we'll continue to do so in the future. And now with that, I'll now turn the call back over to Scott for Q&A.

Operator:

Thank you. [Operator Instructions] First question comes from Doug Leggate from Bank of America Merrill Lynch. Doug, your line is now open, please proceed.

Rick Muncrief:

Good question. One of the things that we’ve talked about in improving productivity, really across the company is focusing on capital program as we go into 2024. Obviously, throughout this past year, we’ve done a fair amount of assessment across our resource base and virtually all of our basins. And so I think that what we have learned, we’re going to watch the performance from those wells that we did the assessment on. And then furthermore, as we’ve talked about, really zone in on some of our most productive areas. And so I think while the market may not have fully appreciated the value of assessment work, we know over the long haul that’s how you truly build inventory organically, and it’s very, very helpful for us. So I think that’s the thing that investors need to watch for is we’re going to stay very focused there. Can you repeat the second part of your question?

Rick Muncrief:

Okay. I was expecting it then. Yes, so…

Rick Muncrief:

Right. Well, I mentioned the – that’s how you can build inventory organically. And I think that that’s the thing I really value about the staff that we have here. We’ve got the depth and the breadth, and we talk about the resource that we have here in-house. And so at times you need to spend a little money assessing some of those resources. That’s what we’ve done in 2023. And so what you’re hearing us say today, we’ve learned some things, we’re tightening some things up, and we’re going to watch some performance, and we’re going to be very, very focused going into 2024. Clay, you have anything, you want to add to that?

Doug Leggate:

Okay. We’ll watch with interest. Thanks for that, Clay. Gosh, I’m torn on what to ask next, but I’m going to go with the variable dividend question. M&A was the other one, Rick, but I’m guessing you wouldn’t answer that. I guess, Jeff, you – sounds like you’re starting to recognize the opportunity to transfer value from debt to equity with your balance sheet comment, but you haven’t ruled out the variable dividend despite the comments around buybacks. Why not just take the variable off the table? Because if I may say so, it seems to me your share price hasn’t had any value recognition for that whatsoever.

Doug Leggate:

That’s very clear. Thanks very much, guys.

Operator:

Our next question comes from Nitin Kumar from Mizuho. Nitin, your line is now open. Please go ahead.

Rick Muncrief:

Good morning.

Rick Muncrief:

Yes, a lot of it, to be honest with Nitin is and I think that we’ve actually talked here internally, if you think about our rig count, about two-thirds of our rigs that we have run – are in that area. So that's a good way to look at it. So two-thirds of that number that you see is pretty accurate, we think. Clay, anything you want to add to that?

Nitin Kumar:

Great. Thanks. As I follow up, Rick, I'm going to not assume that you won't answer the M&A question. So look, industry consolidation is certainly front and center. You have been part of that consolidation in the past. Can we maybe get some thoughts – updated thoughts on how you're viewing the go forward path for Devon, either as an independent company or as a consolidator?

Nitin Kumar:

Thanks, Rick. Thanks for the answers.

Operator:

Our next question comes from Neil Mehta from Goldman Sachs. Neil, your line is now open. Please go ahead.

Rick Muncrief:

Yes, thanks, Neil. I appreciate the question. We've been staring at this kind of saddle in fourth quarter, first quarter for quite a while. We don't provide detailed guidance, typically ahead of the coming quarter. And so having the activity really that fourth frac crew in the front half of 2023, we've benefited certainly in this quarter and we'll see a rollover in the fourth and first before we build that duct cadence back up again and we're able to bring that fourth frac crew up. That provides some lumpiness. We realize that's not ideal. We're trying to make sure that we telegraph not just this fourth quarter, but the first quarter has a little bit of a saddle as well. I think once we get that frac crew back, we reestablish the higher rate. It's pretty – it’s steadier throughout the year. So think of two, three, four being a little bit flatter. The fourth could come down just a little bit, but probably not quite as much as a saddle as we saw in this fourth and first coming quarters.

Jeff Ritenour:

Neil, so we do a lot of work, as you can imagine, we talked last quarter about some of the work we do with the board and back in September really looking out five and ten years. And that leads to a kind of a more focused look this time of year, November; we have a call with the board. We're really starting to kind of firm things up. During that process, we run lots of sensitivities, the what ifs. We think about different deflation cadences, how that impacts us, different capital allocation. And what we've gotten to is we feel really good about this plan, refocusing as we've talked about on the Delaware Basin, benefiting from the work that we've done in 2023, around some of the assessment work. And so leveraging into that, we feel really good about the continued focus of the activity that we have and paring back on some of the other basins that probably could use a little bit more breathing room. And then feel really good about the deflation that we’ve baked in. Call it roughly 5% or so that we have in hand today we feel really good about those numbers. The balance, the remaining 5% is a little bit pair back in activity, and then of course, we’re striving to exceed those expectations every day inside our shop.

Rick Muncrief:

Thanks, Neil.

Scott Gruber:

Yes. Good morning. Want to get just a bit more detail on the infrastructure constraints in the Delaware. It sounds like it’s starting to improve. But are you still seeing some peak rates constrained? Is it still impacting where your rigs are running today? And if the answer is yes, when do you think these constraints can be fully alleviated?

Scott Gruber:

Got it. And just a quick one following-up on the budget. Do you have a rough sense for the well count that’s incorporated in your budget for next year?

Scott Gruber:

Okay. I appreciate it. Thank you.

Operator:

Our next question comes from Neal Dingmann from Truist. Neal, your line is now open. Please go ahead.

Rick Muncrief:

Yes, I think you try and plan this stuff years in advance because many of these big projects are multi-year projects and sometimes those projects slip. Ultimately, funding decisions are outside of your control. So some of those things can be typically accounted for and baked in. What we’re really focused on in 2023 is making sure that we’re honoring our flaring percentages. We’ve done an amazing job of driving that down. We’re really thoughtful about these outlets and making sure that we have the ability to flow these wells back. And so we want to make sure that we’re staying ahead of any bumps and disruptions. As you know, in the New Mexico side, it’s a lot more federal land. You’re relying a lot more on the BLM, even small things like right away, which are pretty standard course take a little bit longer these days. And so during that transition, when we’re accounting for that and our third-party partners are accounting for that, there can be a little bit of an extended drag. I think we’ve gotten a lot of really good important progress during the course of 2023 that we will benefit from. But we will continue to see constraints all the way around the Permian Basin as this is a materially growing basin that’s so incredibly prolific.

Clay Gaspar:

Yes. Neal, I would say it was a combination of – we did some assessment work. I highlighted on the last call, specifically the B zone. Really understanding, how does this work as we co-develop? How does this work independently? What’s the right business decision? And that takes time to evaluate. So that’s some of the things that we did dozens of other tests as well. But some of the work that we invested in during the course of 2023. Some of the things that we’re learning, obviously, we’re applying to 2024. And then parallel to that was the infrastructure comments that that I just went through. So I think there’s a parallel as we think about what this concentration of activity means. Again, I’ll go back to the kind of two-thirds, one third of our inventory is in the New Mexico side. So we’re not overly leveraging New Mexico versus Texas. Now, we’re certainly high-grading. We’re always trying to drill our best stuff first, but that’s no different than what we’re doing in other basins. And obviously, other operators are doing as well.

Clay Gaspar:

Me too, Neil.

Charles Meade:

Good morning, Rick, Clay and Jeff. Clay, I want to take one more run at the Delaware Basin infrastructure question. As you were making your prepared remarks or earlier Q&A, I wrote down there’s electricity build-out, compression, processing, takeaway and then also you added water. And so as you look at – if those are the right categories, as you look at those, could you tell us what’s your best guess for 2024? Or is it going to be your top one or top two concerns? And I’m less thinking about where you have work to do, but more in the framing of what’s – which of those is most likely to emerge as a bottleneck in 2024?

Rick Muncrief:

Charles, this is Rick. I’d like to – I’d like to add. Yes, sorry. One thing I’d like to add is, we are really pleased with how the midstream providers are building out their capacity. So we think that some here in the next six quarters to eight quarters, you’re going to see another 2 Bcf a day, plus or minus, in the Permian Basin of processing. So when you step back and you look at the capital investment on the midstream, you look at the long-haul getting pipe built in the ground, getting those getting out of the gas to the Gulf Coast area and then over into Louisiana and there are areas like that for the LNG facilities. We just think the – the right amount of focus is being placed on it, and I feel very confident in future. And the other thing I’d say, I’ve got is a pretty good time to interject this, but we continue to see growth into Mexico. That is a market that has grown from 2 Bcf a day up 6 Bcf, 7 Bcf a day, and there’s no basin more well suited for that, I think, than the Permian when you start looking at Western margins of the Permian Basin. So whether you’re on the Delaware side, the Midland side, you’re going to benefit I think, from that Mexican growth over the next decade or two.

Rick Muncrief:

You’re reliant than I am.

Jeff Ritenour:

Yes. I appreciate that, Charles. And I think your last comment is important because that’s why we want to maintain flexibility and we believe the framework that we have today allows for that as we kind of navigate the different market conditions and whether that’s specific to Devon or on a more macro basis. As it relates to how we evaluate the share repurchase, I think I’ve talked about this in the past, but just like you all, we have our own internal models, obviously, around intrinsic value, but we also watch closely how our peers are trading, how we’re trading relative to them. And I think without question, you’ve seen compression of our multiple over the last 12 months. And so we sit today, it feels pretty clear to us. Given what we know and how we feel about the go-forward business, which I thought Clay did a great job of articulating our game plan here over the next 12 months. We feel like it’s a right time to jump in and be more aggressive on the share repo than we’ve been in the past. And so you’ll see us execute that over the coming quarters. And it’s always a little bit challenging with the earnings blackouts that we have as it relates to the timing of how that plays out. But we’ve got a game plan to go execute on that and be pretty consistent as we move forward over the next several quarters.

Operator:

Our next question comes from Matthew Portillo from TPH. Matthew, your line is now open. Please go ahead.

Clay Gaspar:

Yes. Thanks for the question, Matt. I’d say it’s all a very much a work in progress. Definitely the South Texas Eagle Ford area is a maturing basin, similar to Williston, but very different in many ways. The rock is incredibly forgiving in the sense of down spacing refracs. We continue to find and uncover new ways to extract more and more of that oil in place. So we’re very encouraged with that. Now that said, it doesn’t always come out exactly as planned. I would say it was less about the learnings around down spacing more, a little bit about regional. And so as we moved into specific areas, we found that one, the recipe from what we call the Black Hawk area kind of our legacy business, isn’t exactly the same recipe as we reply to our Falcon, the new assets. And so some of those learnings certainly have accounted in for the results in 2023. We have a little bit less activity during this quarter. So you saw the oil production rollover second quarter, third, I’ll caution to look back, make sure you look back at the first quarter because we had about a 10% improvement or increase in production quarter-over-quarter from one to two, and then a down from two to three. So that’s more related to activity, less about individual well results. But as we continue to explore refracs down spacing combinations of how we do this co-development, I would say we’re very encouraged about what we’re seeing there. And this rock continues to be the rock that keeps on giving.

Rick Muncrief:

Yes. It’s a really good question, Matt. I think I’m going to start the Anadarko there. So we actually were running four rigs. We dropped a rig as you probably recall mid-year. The Dow partnership we have is going really well. Even though the strip is supportive for gas, the outlook we think is really good. One of the things that we were faced with or we made the decision to do is just scale back at capital just a little bit and going from four to three rigs. We think that’s the right thing to do. Obviously, the promote keeps those returns in a pretty good spot. So that’s how we’re looking at that. I think, as we go into 2024, we plan to keep a three-rig program is our plan. Now up in the Powder, we – our original plan contemplated running two rigs, possibly even considering a third rig up there just because some of the encouraging results. But the fact of the matter is that we are still challenged somewhat on the well cost a little bit. And that some of that’s just a function of your activity level being somewhat depressed quite honestly, or slower than you need to drive those costs down. We’ve made a decision to be just returns focused and make sure that we get that capital efficiency increase that we referred to. And the best way for us to do that is drop that back to one rig versus the plan two or three. It’s a – I think it’s the right thing to do short term. Now, longer term, we know that you need to put additional capital in there. So we’re working with service providers. See if we can see some creative ways to do that. But that’s probably something we’d need to contemplate more into 2025. But we are seeing some, right, some really encouraging results. So real pleased with that asset at that point in time.

Operator:

Our next question comes from Kevin MacCurdy from Pickering Energy Partners. Kevin, your line is now open.

Clay Gaspar:

Yes. I've always struggled with the maintenance capital question because there's always a way to kind of game the system. If you just want to focus on oil or gas or whatever, I would say this is a maintenance capital with a longer-term mindset in mind because we are still doing work to really prove up future value. We're doing things to always kind of enhance our portfolio. At the same time, maintenance capital of essentially roughly the same production 2024, excuse me, 2023 to 2024. And then as we look out to 2025, we're at least that level, maybe a little bit of growth in 2025 based on this investment. So yes, rough numbers, I would call that a maintenance capital, but a healthy maintenance capital.

Clay Gaspar:

Yes. We are certainly still nailing things down, and this is all preliminary based on the Board's approval. But I think directionally, you're right. We had looked at what is the constant two rigs for us to operate scenario look like? What does a one-rig for us to operate scenario look like? And then, of course, we're working with our JV partners BPX [ph] on activity level for that side of the base in the Black Hawk side. And so I think what we're working towards and we're finalizing looks like a high-graded activity consistent with what we've talked about in the other basins. And you'll see a really nice uptick in efficiency – capital efficiency from that. Now still bear in mind, I mean, we're doing some really inventive things there. We're looking forward on a lot of projects. We're not starving the asset of how do we create more value moving forward. That's very important to us that we're balancing the short-term wins with also longer-term value creation.

Clay Gaspar:

Thank you, sir.

Paul Cheng:

Thank you. Good morning guys. Two questions, please. You guys have been indeed over there and that you have seen a lot of improvement. So if I'm looking out for the next one or two years, where is the area that you see the most opportunity for you to further improve? The second question is on the Bakken. You've been struck over there. I think from that standpoint, what have we learned from the RimRock acquisition in terms of future A&D, due diligence process and all that. And whether Bakken, given your substantially reducing activity what's the role for your longer-term portfolio? Do they have a role there? Thank you.

Clay Gaspar:

Yes. I'll go back to kind of what are we excited about when we look at the footprint that we have today, as we think about innovation in that space, Paul, last week, I did a couple of days of intensive conversation did an off-site with my team. And we're really focused on what distinguishes us two years from now, five years from now. And most importantly, what are the actions that we can take to ensure that exceptional performance. I think the two year conversations, there was a lot about recovery factor. How do we intent – how do we intentionally go after more of that oil that we already knows there. We sit in five amazing basins, have incredible land footprints already under our feet. And how do we think about extracting just a little bit more from the resources that we have. So a lot about stimulation design, a lot about integrated approach, thinking like geologists and reservoir engineers and completion engineers all at the same time in extracting that value really leaning in some of the great work that we found around refracs, some of the other things that we have. And as we move towards five year really things start coming in more focus around things like enhanced oil recovery, how are we progressing those learnings. And again, leveraging the amazing footprint that we already have today, how do we enhance that ballpark 10% recovery to 12%, 15%, 20%, essentially doubling the resource that we have. Specifically, the learnings around the acquisitions that was a little bit more than a year ago. We're still a pretty fresh team. I can tell you, the acquisitions were fantastic. Value-creating opportunities for us. They fit the portfolio. And what we really learned is that we need to do a better job in the process of the handoff and how do we pick those opportunities up. When these companies, the prior owners may have a little different mindset on how far ahead they are on infrastructure, on permitting, on how they manage the day-to-day operations things like ESG or a very high important factor to us. So moving through that kind of – that transition period, I think we have gotten materially better from the first to the second and when the third one comes, we'll make another material improvement. So real pleased with the team, the work that David's team, the greater team does in that evaluation. We're in every day to the room, we'll look hard at everything. We keep an exceptionally high bar and we'll continue to get very much better on that handoff and really improving the ultimate value from these opportunities.

Operator:

Our next question comes from Scott Hanold from RBC. Scott, your line is now open. Please go ahead.

Jeff Ritenour:

Yes, Scott, you bet. The answer for the third quarter is real simple. As you'll recall, at the end of the second quarter, we disclosed our cash balance a dip below $500 million. As you might recall, when we rolled out our framework three years ago, one of the key criteria was that we maintain a cash balance in excess of that $500 million level. So our first priority was to take care of the maturity that we had in the third quarter. Second priority was to build back our cash balance above that $500 million level, which, as you saw in our reported results here in the third quarter, we've done that. So that married with our commitment to deliver on the variable dividend that we talked about in the previous quarter. We weren't in a position to buy any incremental shares in the quarter. But going forward. We've – I think we've hopefully clearly telegraphed today our intention on the share repo as well as the potential impact to the variable dividend going forward. And so look forward to getting to our next call in February and kind of talking about the results.

Rick Muncrief:

Yes. We think it's a new baseline. The fact is we – not too dissimilar from what the consensus was is that 320 was probably certainly doable. We've done it two or three quarters in a row. But the reality is, as we continue to see some constraints, some weather issues and real-world impacts, we think that 315 is absolutely the right baseline for us.

Scott Coody:

Well, I appreciate everyone's interest in Devon day. I see that we're at the top of our time. So if you have any further questions, please don't hesitate to reach out to the Investor Relations team at any time. Once again, thank you for your interest, and have a good day.

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.

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?

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?

Operator:

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

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.

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.

Operator:

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

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?

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?

Nitin Kumar:

Great. Thanks for the answer, Rick.

Operator:

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

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.

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.

Operator:

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

Rick Muncrief:

Good morning, Arun.

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.

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.

Operator:

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

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.

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.

Operator:

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

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.

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.

Operator:

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

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.

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.

Operator:

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

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.

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.

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.

Operator:

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

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.

Paul Cheng:

Thank you.

Operator:

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

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 first quarter and our outlook for the remainder of 2023. 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 US 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.

Clay Gaspar:

Thank you, Rick, and good morning, everyone. As Rick touched on earlier, our team did a great job of meeting the first quarter operational targets through solid well productivity, effective cost management and the steady progression of upcoming development projects that will benefit us over the coming quarters. Remember, we're focused not just on delivering the numbers for this quarter and year, but also derisking opportunities for the coming years and also investing in R&D that will create value throughout the coming decade. We're making great progress on all three fronts. This positive start to the year put us in great position to continue to build momentum throughout the course of the year and achieve our corporate objectives for 2023. A significant contributor to the success in this quarter was our franchise asset in the Delaware Basin. As you can see on slide 15, roughly 60% of our capital was deployed to this prolific basin, allowing us to run a consistent program of 16 rigs and four frac crews in the quarter. With this level of drilling and completion activity, we brought online 42 new wells in the quarter, with the majority of this activity targeting high-impact intervals in the Upper Wolfcamp. This focused development program resulted in another quarter of volume growth year-over-year, with oil representing 51% of the product mix. While we had great productivity across our acreage position, our performance during the quarter was headlined by our Exotic Cat Raider project. This 6-well pad located in Lea County, New Mexico, targeted a highly productive area with 3-mile laterals in the Upper Wolfcamp. Individual wells at Exotic Cat flowed at rates over 7,200 BOE per day and well -- per well recoveries from this pad are on track to exceed two million barrels of oil equivalent. The flow rate from this activity rank among the very best projects Devon has ever brought online in the basin. And lastly, on this slide, another key event for us during the quarter was the resumption of operations at our Stateline eight compressor station. This was possible. Thanks to the team's timely efforts in securing replacement equipment and the personnel to safely repair this critical facility. Although this repair work did temporarily limit our production in this part of the field during the quarter, we are confident that we resolved this issue and we do not expect any further disruptions of this nature. Furthermore, we also commenced operations at our Stateline 10 compressor station, providing us another 90 million cubic feet of throughput and even more flexibility in the region going forward. Turning to slide 16. As I look ahead to the remainder of the year, our Delaware asset is well positioned to build upon the solid results we achieved in the first quarter. Overall, with the 200 wells that we plan to bring online this year in the Delaware, we expect well productivity to be very consistent with the high-quality wells we brought online over the past few years. And for context, as shown on the chart to the right, this level of well productivity would not only position Devon among the top operators in this world-class basin, but would also surpass the performance of other top shale plays in the US by a noteworthy margin. This impressive well performance, coupled with a long runway, a high-value inventory, further underscores the competitive advantage and the sustainability of our resource base in the Delaware Basin. Turning to slide 17. Another asset, I'd like to spend some time on today is the Eagle Ford, which is our second-highest funded asset in 2023. Over the past few years, we've taken the disciplined and scientific approach to refine the next phase of development in this prolific field through thoughtful and measured appraisal work. The momentum generated from these learning's is evident in our current capital program, where we are pursuing tighter infill spacing and have active refrac program, with the goal to efficiently sustain a steady production profile and harvest significant free cash flow. This year, we plan to spud over 90 wells, with the majority of this drilling focused on redeveloping acreage with much tighter spacing than originally conceived when we first entered the play a decade ago. We attributed this infield opportunity to high reservoir pressure, a fractured network that heals quickly and low but consistent permeability. This unique combination allows us to pursue significantly tighter spacing, with redevelopment activity targeting 16 to 20 wells per unit across multiple landing zones in the Eagle Ford. In addition to the benefit of oil-weighted recoveries that are projected to exceed 0.5 million barrels per well, our ability to leverage this existing infrastructure in the play also bolsters the returns. These unique and favorable reservoir characteristics in the Eagle Ford provides us with many years of highly competitive drilling inventory. The team has also made steady progress on our refrac program in the Eagle Ford, achieving consistent, successful and restimulating the productivity of older wells. To date, we have roughly 30 refracs online that have successfully accessed untapped resource, resulting in an immediate uplift to the well productivity that has expanded per well reserves by more than 50%. In 2023, we plan to execute around 10 refracs and we've identified several hundred high-return candidates across the field to pursue in the future. While we have made significant progress on improving recoveries through infill spacing and refracs, we believe there's still meaningful resource upside in this play. A catalyst to help us accelerate our learning's in this area is our Zgabay pilot in DeWitt County, which is supported by a grant from the US Department of Energy. The objective of this grant is to fund as field study and create an underground laboratory to improve the effectiveness of shale recoveries by testing new monitoring techniques for both initial stimulation and production as well as collecting critical data to enhance recoveries via refracking and EOR. While we're still in the early stages of gathering and interpreting the data from this project, we have already incorporated learnings into our day-to-day operations. These learnings will enable us to optimize recovery of resources, not only in the Eagle Ford, but across our broader footprint in the US I expect to have more positive updates on this topic in the future. And finally, on slide 18, I'm also excited to talk about the positive results we're seeing delivered on other key assets across our portfolio. As you can see on the graphic to the right, over the past year, we've done some good work to opportunistically build up operating scale in these areas and increase the production by 9%. The main factors that drove this growth were our Dow JV partnership, which helped us regain operational momentum in the Anadarko Basin, the RimRock acquisition in the Williston and the quality assessment work we've done in the Niobrara oil play in the Powder River Basin. That has helped us build for the future. In addition to solid production growth, this diversified group of assets is on pace to generate a meaningful tranche of cash flow that we can deploy to other key strategic priorities such as the return of capital to shareholders. I appreciate the team's hard work and the effort that goes into delivering near-term free cash flow and also derisking valuable future inventory. With that, I'll turn the call over to Jeff for a financial review. Jeff?

Rick Muncrief:

Thank you, Jeff. Great job. I'd like to close today by reiterating a few key messages. Number one, our team did a superb job of meeting the operational targets we set out for ourselves in the first quarter through solid well productivity and effective cost management. Number two, our disciplined execution resulted in another strong financial performance for the company. This is evidenced by the attractive per share growth we're delivering, substantial cash returns realized by investors and the high returns seen on invested capital. Number three, with a solid start to the year, we're now on track to achieve all of our capital objectives in 2023. Inflation is showing signs of plateauing and our business is well positioned to build momentum and generate substantial free cash flow as we progress through the year. Number four, and lastly, we have the resource depth, execution capabilities, financial strength and disciplined business model to continue to deliver sustainable results through the cycle where a premier energy company are also perfectly positioned to benefit from this multiyear upcycle. And with that, I'll now turn the call back over to Scott for Q&A.

Operator:

Thank you. Our first question comes from Neil Mehta from Goldman Sachs. Neil, please go ahead.

Rick Muncrief:

Well, Neil, I think we're watching a lot of things. We have seen a softening in the market, but I think as we've laid out in our guidance, there's really no change. We'll see how it plays out through the year, but as I alluded to, and then Clay had in his prepared remarks, we are seeing some softening and we'll just see on how that plays out. But I do see right now, no change.

Rick Muncrief:

Yes. It is strictly time. And I'll have Clay weigh in, also more color, Neil.

Neil Mehta :

Make a lot of sense. Thank you guys.

Operator:

Thank you. Our next question comes from Arun Jayaram from JPMorgan. Arun, please go ahead.

Clay Gaspar:

Sure, Arun. Good question. I appreciate it, and I'll look -- I'll pan out just a little bit because we did RimRock and Validus kind of back to back. I would say, from an integration standpoint, they've both gone exceptionally well. We certainly learned some things on RimRock, we immediately applied to Validus and always looking to continue to get better. Specifically on the Validus side, we're certainly learning things, I've alluded to in some of my remarks, additional upside that we didn't even contemplate in that acquisition. On the RimRock side, or the Williston, really the Northern US, has been plagued by some pretty cold weather. That has not -- we've definitely been affected by that. And then digging out from that, everyone is reaching for those workover rigs, kind of all reaching for the same equipment, so there's a little bit of a backlog associated with that. And then honestly, we've seen a little bit of more offset frac activity that we've shut wells in for, so that impacts things. But one of the things we're learning about the late innings in Williston is some of these wells would have kind of complicated depletion metrics to them. So you have -- might had a crosscut well that has a lower -- a little bit more depletion in part of that lateral. That's causing some interesting things around how do we clean these wells out, how do we provide the right artificial lift. We've made some really good strides there. Really excited about the latest group of wells that are coming online. But I think all three of those factors have caused us to probably underperform a little bit in the second quarter relative to expectations, first and second quarter. But I see that already in the second quarter, things are starting to pick up, and I'm really excited about that asset and it continues to be such a critical piece of Devon's portfolio.

Clay Gaspar :

Yeah. There's a lot of it going around the company and a lot of stuff that we're -- is pretty early innings. We're not talking a whole lot just yet, but one that we are talking about is in South Texas, the Zgabay project, in particular Department of Energy-funded, something that we've shared pretty broadly with the industry in a number of forums. And the real win so far have been from completion design, refracking and then the earliest knowledge we're getting around some EOR, some enhanced oil recovery. So that's all very exciting. I can tell you we've already put some of that information to work. The refracking activity is very encouraging. Some of that is pretty unique to the Eagle Ford. Talked about some of the reservoir characteristics there. It has an ability to stay really -- the original completion tends to stay very near wellbore, and so it gives you that opportunity to feather in a few more wells or other basins. That just really doesn't work very well. And then the re-stem, figuring out the techniques how to go about this, how to prosecute this and we've seen tremendous upside. So all of that is great inventory. And most of it, to be honest, is upside from what we underwrote with the Validus acquisition.

Operator:

Thank you. Our next question comes from Neal Dingmann from Truist. Neal, please go ahead.

Jeff Ritenour:

Yeah, Neal, this is Jeff. Yeah, thanks for the question. What you're going to see from us is more of the same on the model, and you described it well, which was certainly to the extent where we see opportunities to buy back our shares, when we see that valuation dislocate, if you will, from our view of the intrinsic value which certainly happened in the first quarter. Post our February call, we saw the stock trade on a relative basis to the peers in a negative way. And we jumped in with both feet and bought back shares in a big way. We think that's the beauty and the balance of our -- the flexibility of our model, which is it provides us the cash and the wherewithal to go take advantage of those opportunities. So moving forward, that's absolutely our expectation. If we see the stock trade off relative to the group or dislocate from our view of intrinsic value over the longer term, you should expect for us to lean in on the share repurchase program. All the while, our first priority is to sustain and grow the fixed dividend, which we plan to continue to do, and then feather in the variable dividend, the -- up to 50% of our free cash flow in any given quarter is going to go to the variable dividend. So that flexibility and balance that we have in the model, we think has served us really well over the last three years, and you should expect that to continue going forward.

Rick Muncrief:

Yes. Thanks, so Neil, I mean, we've -- I mentioned Clay and Clay drove home the point. We're really confident in our infrastructure -- actually the recovery and from downtime. And more importantly, we are staying ahead of it. We have a great team that -- on the build-out. It's working really well. And then we have third-party providers that we have great relationships with, and we have a tendency to try to work a year and two and three years down the road. And when you've got the inventory we do, the execution you do, you can sit down with people and plan that out because that's what the Permian is going to continue to need year after year after year as continued infrastructure growth. And I'd say it's going really well.

Operator:

Thank you. Our next question comes from John Freeman from Raymond James. John, please go ahead.

Clay Gaspar:

John, I will wing it a little bit. I think it's about 20% this year that we're going to be drilling the three-mile laterals. It's always a little bit in flux. We're always trying to trade the opportunities. I can tell you, our -- we feel very confident in the returns of the two-mile laterals. That's kind of our go-to with most of our acreages set up. I think it's just really where we see those opportunities to turn a one mile into a two or turn a few ones into a three, those turn into really phenomenal economics. So what I would say is operationally, we're very comfortable drilling three-mile laterals today. I think we've got that recipe down. So operationally, it's not a challenge. It's strictly just looking at the land and where is it set up for 2s and where is it set up for 3s.

Jeff Ritenour:

Yes, John. You're exactly right. As it relates to the contingency payments, it varies obviously by commodity price, both oil and gas. And at a $65 oil price, which above a $65 oil price where we are today, we would expect to receive around $20 million. And then from a gas price standpoint, it's tiered from $2.75 all the way up to $3.50, and the variability there is anywhere from $20 million to $45 million. So, where the current strip sits today, I haven't looked at -- you're probably somewhere in the mid-3s, I would guess. So that would be another $25 million or $35 million that you could expect to receive on top of that oil payment.

Jeff Ritenour:

Thank you, John.

David Deckelbaum:

Thanks for taking my questions today guys. Just wanted to follow up on some of the thoughts around the buybacks in the first quarter and using the cash balance opportunistically. Does that in any way sort of inform your view on how you're looking at further consolidation this year? Obviously, Devon was a pretty active participant last year, but are the opportunities that you're seeing in the A&D market just sort of less robust than what you would have seen last year relative to the on value of your own stock?

David Deckelbaum:

I appreciate that. And Clay, if I could just ask a little bit more about ZGABAY. Just more around the scope of the project, how long the DOE grant last for in this partnership? And then, in terms of EOR, are you looking at gas re-injection, or is it all CO2? Is it mostly re-fracs? I guess just the total scope and duration and how this would be applied to some of your other active basins.

David Deckelbaum:

Thanks Clay and thanks for your time guys.

Operator:

Thank you. The next question comes from Matthew Portillo from TPH. Matthew, please go ahead.

Clay Gaspar:

Hi Matt.

Clay Gaspar:

Hey Matt, this is Clay. Great question, in the last 12 months, we've kind of tested every flavor of commodity price. High oil price, low oil price, high relative gas price, 10:1, it was $80 and $8 at one point. And so we've run the sophisticated model that we have in a number of scenarios really looking for when does our portfolio really command that we shift the capital allocation materially? And what was interesting is, in all of those scenarios that we ran even some of the gas-levered opportunities, it still said keep pushing towards oil, keep pushing towards the Permian, the Delaware Basin. We're still always commanding capital first. As we've matured our understanding of places like the Eagle Ford, certainly, it's risen up. And with the acquisition of Validus, it's commanding more capital, as I mentioned earlier. As we stress test the gas side, certainly, things like the gas-prone areas of the Anadarko become more stressed. But remember, the preponderance of our investment is on the Dow JV, which is the gas condensater. So you get a high -- significant amount of condensate in those wells, and then also that carry really helps us support pretty phenomenal economics even in this commodity price environment. Now look, we're always watching. We're always rerunning this. This isn't a single once-a-year scenario. This is a monthly exercise. We're always stress testing, and you can bet we're making changes on the margins. We will pull a few wells out of the system for this year, replace a few as opportunities come our way. Maybe it's a trade that just came to us or a new opportunity that the team has discovered. We're always evolving on the margins. But what I can tell you is our program is very consistent and very robust, certainly even in today's commodity price and service cost because we believe the service cost is still decoupled from today's commodity price.

Clay Gaspar:

Matt, great question. I love talking about the Powder because it is kind of behind-the-scenes. It is something that I'm really, really proud of the work that the team has done. On the front end of the challenge is de-risking the productivity. Making sure that when we drill a well, wherever we are in the basin, that we have a good understanding of what it can deliver. The second order is how do we get the cost structure down, so that we generate the right competitive return? I can tell you on the former, we've made tremendous progress, and that's really exciting. To me, that's the -- if you don't have good rock, you can't do anything about that. We've got good rock. We've been able to improve the productivity, prove that up time and time again. On the well cost, to me, that surface considerations that we can always improve on. Have a tremendous confidence in the team to be able to drive those costs down in time. And so that is something we're now working on to ultimately get to a place of more competitive and sustainable returns. But we've got a ton of inventory there. It is very oil prone, and that will certainly have its day in the sun in the coming years. So really great progress from the team there.

Clay Gaspar:

Thanks, sir.

Scott Hanold:

Yes, thanks. Hey, Jeff, I was just kind of curious. When you step back and look at the balance sheet, I mean, you got about $800 million, $900 million of cash. I know you talked about the debt coming due, you want to take down later this year. But as you start thinking about the quantum of incremental buybacks, do you all just really focus on what is left in free cash flow, or is there some optionality to utilize the cash balance? And any color on kind of working cap per -- cash needs per working capital too would be helpful.

Scott Hanold:

Thanks. That's a good answer and maybe this one is for Clay. When you think about the tighter spacing in the Eagle Ford, I know we've -- the industry has gone from tightening and widening and tightening in whether it's a Permian and the Eagle Ford before, and it seems like there's always an aptitude to eventually go back to wider spacing when oil prices come down. But can you kind of speak to the resiliency of this tighter spacing if we do see lower oil prices? Do you guys think you'll stick with it, or is that just work given the current context around oil prices in the strip?

Scott Hanold:

Fair enough. Thank you.

Doug Leggate:

Thanks. Good morning everyone. Thanks for taking my questions. Rick, it's not so long -- it's not so long ago that Devon was not only the best performing stock in the sector over an extended period, but the best performing stock the S&P 500. I think it was most of 2021, if I recollect. I'm wondering, given that one could argue the market has, therefore, recognized the value of what the combined company is and benchmarking the free cash flow capacity with some additional tax headwinds perhaps going ahead, I'm wondering how you would characterize your value proposition today? What do you think you need to do to break out beyond just a call on the commodity?

Doug Leggate:

Okay. I know it's a tricky one to answer, and I appreciate your perspective. My follow-up is on the 0% to 5% growth. Not target necessarily, but outcome that you laid out at the time of the merger. Obviously, the incremental bolt-ons have got you there this year. What about the go forward? And I'm thinking what would the capital budget have to look like to support that? And do you think 12 years of inventory, is enough to support that kind of go-forward visibility?

Doug Leggate:

I like shared comment. Thanks so much, Rick

Operator:

Thank you. Our next question comes from Paul Cheng from Scotiabank. Paul, please go ahead.

Jeff Ritenour:

Yes, Paul, this is Jeff.

Jeff Ritenour:

Yes. I was just going to say again, Paul, and we talked about this a lot with you in the past. With us, it's all of the above. So we've delivered on a sustainable fixed dividend which we're growing over time. We've got the framework which allows for the variable dividend up to 50% and then stock buybacks on top of that. We're not biased to one or the other. Over the long term, we think that balanced approach makes the most sense. Certainly, as Rick mentioned earlier, to the extent that we see an opportunity to jump in and buy back our shares when we see a dislocation versus intrinsic value, we're going to do that, and that has the opportunity to accrete per share growth for us over time. But at the end of the day, it's about total shareholder return, right? It's not just the dividend, it's not just the buyback, it's not just the stock price, it's that total shareholder return. And we think over the longer term, this model and this balanced approach will deliver the best results. And I'll point out over the last two years, we're the number one company as it relates to total shareholder return and that includes the last several quarters. So we feel pretty confident in our game plan. We're going to keep our head down and execute and deliver on that game plan. And we think when we wake up many, many years from now, we will have delivered a great result for shareholders.

Clay Gaspar:

Hey Paul, I'm going to fuzzy that number. On the 20%, reminder, that's a rough number for this year and probably a little bit rougher. But I would say directionally, it's probably about the same, maybe a little bit lighter to that number as I think forward on the inventory. Remember, a lot of this happens kind of evolves in our land shop as they make trades and kind of extend that runway a little bit, so it's a pretty healthy number. Our standard is two miles. Again, the returns on two-mile laterals in the Delaware Basin are phenomenal. And so we don't need that three-mile to make the numbers work. But when it comes our way, it sure is a nice thing. And once again, I feel very confident in our operational ability to execute on three-mile laterals. That's become a fairly standard fair for the team in the Delaware.

Clay Gaspar:

Yes, we've drilled three-mile wells in multiple basins. And certainly, the Niobrara and the Powder is kind of built on a three-mile concept. We've drilled at least 20 years, 30 wells, three-mile wells in the Williston, so this is something that we feel very confident in our ability to execute on. And again, most of our performance, most of our wells we execute on are actually about two-mile laterals in general and that's become kind of our standard. But where the opportunity presents, we feel very comfortable in executing three-mile laterals.

Rick Muncrief:

Thank you.

Roger Read:

Yes. Thanks. Good morning.

Roger Read:

I'd like to come back to a couple of maybe the more operational questions. Your comments earlier about where you're seeing inflation, maybe get an idea of how sort of the, let's call it, disinflation maybe at this point would flow through? Where you're seeing it? Where we should expect to see maybe the bigger benefits?

Roger Read:

Okay. So we should expect not just a decline in cost, but you would expect also an improvement in productivity as you high grade across the board?

Roger Read:

Okay, great. And then my follow-up question is on the refrac wells. I know it's early days in this, but I was just curious, is there a type of well or a vintage of well that works best? And then going back to a question earlier about where you should put your money in terms of the returns. I'm guessing oil over gas. But just as a broad comment, how does the return on a refrac compare to the returns on new drilling, your capital program as currently laid out?

Roger Read:

Appreciate it. Thank you.

Scott Coody:

Well, it looks like we're at the end of our time slot for today. We appreciate everyone's interest in Devon, 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.

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 quarter and our outlook for Devon in 2023. 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.

Clay Gaspar :

Thank you, Rick, and good morning, everyone. In addition to our strong 2022 financial results, Devon also continued a run of strong operational execution as well. As you can see on Slide 14, this was evidenced by several noteworthy accomplishments including a new all-time high for oil production that was underpinned by another year of world-class well productivity in the Delaware. Devon's oil-weighted production mix, coupled with our low-cost asset base, allowed us to capture record margins and maintain low reinvestment rates of just over 30% of cash flow. We also efficiently expanded our resource base in 2022 with proved reserves advancing 12% through the combination of strong drilling results and by seamlessly integrating two property acquisitions during the year. Flipping to Slide 15. You can see that these strong operating results in '22 also place us in the top echelon of capital efficiency for the entire industry, differentiating Devon in this crowded and competitive space. These operational achievements across every phase of the business demonstrate the power of Devon's advantaged asset portfolio, the success of our rigorous capital allocation process and the quality of our people to extract the most value out of these assets through superior execution. For the remainder of my prepared remarks, I plan to discuss the key capital objectives and catalyst of our '23 operating plan. For '23, we plan to maintain a very similar activity level as compared to the fourth quarter of '22, which was the first full quarter of operations with our recently acquired assets in the Williston Basin and Eagle Ford. Overall, we plan to run consistently 25 rigs throughout the year, resulting in approximately 400 new wells placed online in 2023. Turning to Slide 16. Once again, the Delaware Basin will be the top funded asset in our portfolio, representing roughly 60% of our total capital budget for this year. To execute on this plan, we will operate 16 rigs across our acreage footprint with the sweet spots in Southern Lea and Eddy Counties in the Stateline area of Texas, receiving most of the funding. Approximately 90% of our capital will be allocated towards high-return development activity in the Upper Wolfcamp and Bone Spring while the remaining 10% will be allocated towards delineating upside opportunities in a deeper Wolfcamp that will add to the depth and quality of our inventory in the basin. Importantly, we expect overall well productivity from this program to be very consistent with the high-quality wells we have brought online over the past few years. We are also well positioned to maximize value for our production in the Delaware for the upcoming year. The marketing team has done an excellent job of diversifying across multiple transportation outlets and sales points allowing us to avoid many of the takeaway constraints in the basin. Looking specifically at the gas volumes, approximately 95% of our gas in the Delaware is protected by either firm takeaway constraints -- excuse me, contracts, or Gulf Coast by regional basis swaps. With oil production, we expect our revenue to benefit from access to premium Brent pricing through Pin Oak's export terminal in Corpus Christi. This advanced pricing, combined with low LOE plus GP&T cost structure of around $7 per BOE will drive another year of strong margins and excellent free cash flow from this franchise asset. And lastly, on this slide, I would like to provide a few more thoughts on our first quarter infrastructure downtime in the Delaware. As pointed out on the map, in late January, we had a fire at one of our compressor stations in the Stateline area that severely damaged the electrical system and the [DI] unit. The station is our largest operated compressor facility in the basin with capacity of 90 million cubic feet per day and is a key component to our centralized gas lift operations in the surrounding area. We have secured necessary replacement equipment and the team is currently on site repairing the facility. With this disruption and other third-party midstream downtime in the area, we expect to have a negative production impact of 10,000 BOE per day in the first quarter. With the quick reaction time and the team's focus on safety and recovery, we expect to have this facility back up and the affected production fully restored by mid-March, and we do not expect to have any negative production impacts drag into the second quarter. Turning to Slide 17 and moving on to the Eagle Ford. The team has done a great job integrating the Validus acquisition into our operations resulting in our fourth quarter production nearly doubling to 68,000 BOE per day. With this increased scale, the Eagle Ford will play a much bigger role in our capital allocation in the upcoming year, accounting for just over 15% of our total capital spend. During the year, we plan to run a steady 3-rig program with 70% of the activity deployed towards developing our recently acquired acreage in Karnes County with the remaining capital invested in our JV partner, [WPX] in DeWitt County. Overall, this development-oriented activity is designed to maintain steady production in 2023. Looking beyond the production trajectory, a key catalyst for this asset in the upcoming year will be the continued appraisal of resource upside from tighter redevelopment spacing and refracs. Early results indicate there's a lot more oil to be recovered from this prolific play over time. As we get more data points, I expect to provide more commentary on this important resource expansion catalyst in the near future. Moving to the Anadarko Basin. In 2022, the team's approach of wider well spacing and larger completions design consistently delivered triple-digit returns with the benefit of our $100 million carry with Dow. As we look ahead to 2023, I expect continued value creation as we plan to deploy a steady program of 4 operated rigs once again carried by Dow. This program is expected to result in around 40 new wells placed online, focused on primarily the co-development of the Meramec and the Woodford formations in the condensate window of the play. The carried returns of these projects will once again be very strong, allowing us to maintain a steady production profile throughout the year while harvesting significant amounts of free cash flow. For both the Williston and the Powder River Basins, I want to begin by acknowledging the tremendous job our field personnel did in fighting through extremely challenging weather conditions over the past few months. While operations in the fourth quarter were certainly slowed due to these artic conditions, the production from the business was resilient, collectively averaging 80,000 BOE per day between these assets in the Williston and the Powder River Basin. Looking ahead to 2023, approximately 10% of our capital spend will be deployed across these two plays resulting in approximately 50 new wells placed online during the year. Approximately 2/3 of the Rockies capital activity will reside in the Williston Basin. In 2023, the capital objectives for this asset are to efficiently sustain production through low-risk infill drilling, evaluate resource upside with a handful of refrac test, and generate around $700 million of cash flow at today's pricing. In the Powder, our objective is designed to build upon the 3-mile lateral success from last year by taking the next step in the progression of the Niobrara with spacing tests of up to 4 wells per unit. These pilots would not only help us better understand spacing but also help us inform optimal landing zones and completion designs. The key takeaway here is that Powder is one of the few emerging oil plays in North America, and we have a 300,000-acre net position in the core of the oil fairway providing Devon an important oil growth catalyst for the future. Overall, we're very excited about the prospects in 2023. I believe with the high-quality slate of projects we have lined up for the upcoming year, we expect to continue to deliver top-tier capital efficiency that investors have become accustomed to. We're also well positioned to refresh and add our depth of inventory as we execute on these programs in 2023. A good visual reminder of Devon's depth of inventory and upside potential is on Slide 18. I've covered this topic at length during previous calls, so I won't go through the details today, but I do want to emphasize two key takeaways from this slide. First, we have identified roughly 12 years of high-return development inventory evaluated at mid-cycle prices. This inventory positions us to deliver highly competitive results for the foreseeable future. And secondly, I want to highlight that this inventory does not fall off a cliff at the end of year 12. We expect to systematically refresh this inventory over time as we successfully characterize and derisk the many upside opportunities that exist across our diverse set of assets. And lastly, on Slide 19, we are continuing to make significant strides our environmental performance as outlined in our recently published sustainability report. This comprehensive report details Devon's aggressive mid- and long-term ESG targets, including those highlighted on the right side of the slide as well as meaningful steps that we've taken towards meeting these targets. Our actions demonstrate the priority we have placed on long-term carbon reduction intensity of our operations. I'm really proud of the team's commitment to doing business in the right way, which means balancing three mandates

Rick Muncrief :

Thank you, Jeff. Great job. To wrap up our prepared remarks today, I want to reinforce that at Devon, we are unwavering in our focus to deliver differentiated results for our stakeholders, including our shareholders and employees. To meet these high standards, it all begins with our commitment to be a financially disciplined company that delivers high returns on invested capital, attractive per share growth and large cash returns to shareholders. To achieve these financial goals, we have carefully assembled a long-duration resource base that has high graded to the very best plays on the U.S. cost curve. This resource depth, coupled with the execution capabilities of our team, position us as a premier energy company that can deliver sustainable results through the cycle. Since the merger announcement in 2020, we have delivered on exactly what we promised to do with this disciplined operating model and I expect more of the same in 2023. While we will be slowed down a bit in the first quarter by an unfortunate outage, the pathway to recover is well defined, communicated and the trajectory of our business will only strengthen as we go through the year. Overall, 2023 is going to be another really good year for Devon. And with that, I will now turn the call back over to Scott for Q&A.

Operator:

[Operator Instructions] Our first question comes from Jeanine Wai from Barclays.

Clay Gaspar :

Yes. Thanks, Jeanine. Good question, and happy to talk about it. So yes, we soft guided in the last couple of months, extrapolating our fourth quarter. I think we're very much in line, but it is notably just a touch higher. And so we are continuing to see inflation and I want to define inflation because it's -- as we have conversations at the tip of the spear, I don't sense that we are seeing incremental inflation coming our way. What we have is a maturing of older stale contracts that are coming up to a little bit more kind of current rates. So we experienced some of this in the fourth quarter. We're baking in assumption that we'll see more of this throughout '23. Now some people have wondered on our projection for the second half of '23, do we have any deflation or maybe even an inflection to more inflation in the second half. I would say what we have is a more steady run rate, including just a little bit of incremental inflation, really on the order of maturing our contracts. That may be a little bit on the conservative side. But I think as far as we can see, I think that is kind of what we're experiencing today.

Jeff Ritenour :

Yes, you bet, Jeanine. Thanks for the question. Yes, you're exactly right on the back half of last year as we walked into the acquisitions with the cash outlays there as well as all the noise that you're well aware of related to blackouts during that time period and certainly in the fourth quarter as we we're leading towards year-end, that made it more difficult for us to get into the market. And then frankly, we were just in a position where we wanted to build back our cash balances to maximize our financial flexibility, as I mentioned in our opening comments. Going forward, to answer your question specific to 2023, we do expect to get back into the market in a bigger way. As it relates to our authorization, as you highlight, that authorization kind of wraps up in the second quarter of this year. Of course, just as we did last year, my expectation is we'll have plenty of opportunities to go back to our Board, to reload that authorization to build upon it as we work it forward. And certainly, our expectation here in the first quarter and moving into the second quarter, is it will look more like the pace that you saw from us in the first half of last year as it relates to the buyback and particularly on days like today where we're trading off relative to the group, that's a point in time where you're going to see us be real opportunistic and aggressive getting into the market and buying our shares back.

Nitin Kumar :

Rick, I want to -- I think we're going to spend a lot of time on capital efficiency today, but I want to start with cash returns, if I may. Some of your peers have talked about maybe steering away from variable dividends and more towards buybacks just because the dividend payout is a bit variable just by this term. Can you talk about why the current mix of the fixed-plus-variable and the opportunistic buybacks is the right cash return strategy for Devon in your view?

Nitin Kumar :

I appreciate that, Rick. And just as my follow-up, some of your basin peers have been talking about new technologies that can help improve recovery factors in the Delaware Basin in the Permian. I'm just curious, you mentioned the test that you're doing or the stuff that you're doing in the Eagle Ford. But anything in the Delaware that you can speak to in terms of improving well productivity or efficiencies?

Clay Gaspar :

Yes, I think, Rick, I think you nailed it. I'll add just a little bit of color. I mean I think this is kind of the brave new frontier as we think about the maturing of resource plays. The land capture, the kind of the easy, relatively easy stuff has been done. And so now we are thinking about, how do we take these overall recovery factors and where there are significant opportunities, how do we eke out that next incremental opportunity. I mentioned a couple, continued on a couple of things we're doing in the Eagle Ford as well as in the Williston. I can tell you, all of those things are extrapolatable to other basins as well. Those happen to be two of our more mature assets, where we truly understand the geology, we understand the development. We have the opportunity to kind of feather in some of these interesting approaches. So there's quite a bit of excitement around that. I would tell you it's a little too early for prime time, but you know that our focus is clearly on that as we think further out into the portfolio.

Scott Gruber :

I want to come back to the comment on inflation that at the tip of the spear, you're seeing a bit less inflation. At this juncture, are you starting to sense that some of the gas directed equipment in the Haynesville is starting to get bid into the Permian. And I know you mentioned your base case is for a bit more inflation over the course of the year. It sounds like mainly on contract role. But is there a case building for deflation in rigs and frac pumps before the end of the year, just given where gas prices at?

Scott Gruber :

I appreciate all that color. And then just a quick one on Delaware operational efficiency. It looks like the drills and tills for this year maybe up a handful versus last year, but pretty similar level, but you guys are running a few more rigs versus early last year and you got that fourth frac crew coming in for the first half. Can you just speak to kind of expectations around lateral length and any other factors kind of impacting overall efficiency in the basin, kind of mix impact from wells targeted in the program this year?

Operator:

Our next question comes from Neil Mehta from Goldman Sachs.

Rick Muncrief :

Neil, that's a great question. The foundation for us is really the high bar that we've always had on transactions. And so we'll look at transactions. If it makes sense, we'll compare and contrast that with what you're talking about the share repurchases. And I think what you saw, that's the beauty of our model. We had an earlier question about that. The beauty of our model is we can do a little of all those. And so we paid some great dividends, the share repurchases took place, we were able to pay cash for two very accretive acquisitions, bolt-ons. And so I think that's a winning combination. It really is. Now, I do think that you're going to continue to see consolidation in our space. I think there's consolidation needs to take place, and it's healthy for our industry. And I'm very much in that camp. For us, I can tell you we're going to continue to be disciplined and thoughtful and once again, think about over the long haul. And these be something that can compete. We've got a wonderful portfolio. And so we'll always -- that will always be something we look at as an option.

Rick Muncrief :

Yes. Neil, I'll start and then I'll have Jeff follow-up, clean up any of my comments. But I think for us, we were on record is going out there a year ago, where we felt like gas actually, some of the commodity price has actually got a little bit ahead of itself. And we're a little surprised it went up quite as fast as it did. I can also say that it's come down a little faster than I thought it would as well. But I think it's driven by two things. Number one, certainly was Freeport with the -- you take 2 Bs a day. There is a cumulative impact of that export capability being lost. And then the second thing is probably in a lot of parts of the country, a little milder winter. Natural gas is still -- we all know this it's still somewhat weather-dependent. It's a lot different than crude oil. And so I think that for us, we're going to continue to stay as oily as we can for as long as we can. I can assure you. We just think that's a winning combination. Obviously, there's some strong gas guys out there, they probably are more appropriate to answer the questions. But Jeff, how are you looking at it longer term?

Rick Muncrief :

One thing I may add is even some are more gassy development actually is here in the Anadarko. But you have to remember that a big part of that is on Meramec. And so that's a lot different kind of project than, I'd say, an Appalachia or a Haynesville-type project. Many of these wells IP 1,500 barrels a day of condensate. So they are high liquid content and that's what drives returns. That's what drives our interest in it.

Doug Leggate :

Well, Jeff, everybody, I guess someone else stole my variable dividend question, so I'll have to go with something else. But anyway, nice to be on the call. Two related questions, guys, if I may. And I guess, Jeff, they both might be for you. A year ago on this call, you talked about an ultra-low breakeven around $30. And in your press release yesterday, you talked about -- presentation rather. You talked about a $40 breakeven. It seems that with the moderate inflation, I guess, expectations, those two numbers don't really seem to align. Can you walk through what's changed about $40, $10 increase in breakeven is what you're trying to communicate?

Doug Leggate :

I guess I was referencing moderate versus the fourth quarter. But yes, you're quite correct. Thanks, Jeff, for correcting. Well, thanks for the clarification. I guess my follow-up, it might be for you, Jeff, and it might be for Rick, but I'm looking at the free cash flow in the fourth quarter of 2022. And it's basically the same as the free cash flow in the fourth quarter of 2021 with higher oil and gas price. And I guess my question is that with the deferred tax, it looks like that's going to move lower to your point versus the fourth quarter. On a normalized basis, Q4 would probably be lower than a year ago than -- if the deferred tax moves per your guidance. So I guess my question is, I don't want to say free cash flow has peaked but it kind of feels like outside of a commodity call, it kind of has. And so when you think about creating value in an inflationary environment, how do you expand free cash flow outside there, I say, of something like an acquisition. What do you do to drive value accretion, which is ultimately a function of free cash flow expansion? I'll leave it there.

Doug Leggate :

I appreciate the answer, Jeff. I guess I was thinking about taking out someone else's cost because you have got a strong track record of M&A, but I'll leave it there.

Operator:

Our next question comes from Paul Cheng from Scotiabank.

Clay Gaspar :

Paul, it's Clay. I'm going to jump in on the reserves question, and then I'll let Jeff handle the debt question. So one, I appreciate the question. I'm really -- I want to stress this very importantly. We are super confident in our reserves booking process, the quality of our reserves. This is one of the hidden benefits actually from our merger. WPX had one auditor. Devon had another. We've actually brought in a third party to look at both sets of books and just take a brand-new refresh this year, which has been a great process and inevitably, there's gives and takes, but -- and we just -- we were very, very much in line with this world-class new look, fresh auditor. The nature of reserves in general is that we -- there's no strong incentive to overbook. There's lots of incentives to -- there's a strong disincentive to overbook. And so we want to make sure that we have a conservative outlook as designed by the SEC. I think that the general phrase is much more likely to go up and down. But sometimes you have -- with a five-year rule, there's things that move around. And so specifically to the oil question, you hinted at there was some movement in the rig dedications and the rig focus from some of the Texas assets in Delaware to a little bit more New Mexico focus. And that caused some of those wells to fall off in the five-year rule. And so they fall off one category. Obviously, they can come on in other parts of the additions as well. And so that tends to balance. But when you look at the overall quality of the reserves year after year, there's lots of really important hints to look at, finding in development cost as a run rate. If you think about PUD percentage booking, you think about PUD conversion percentage, there's a lot of things that are kind of very important to look at. When you watch all of those, Devon is in a very, very strong position. We feel very confident about our reserves. There's one other piece and a nuance of the reserves booking that's very important. When you -- first thing you do is you're looking at price revisions. So you make a change on price. The second thing you start looking at are things like cost structure and all of that. And in our case, in everyone's case, but in our case, in particular, our LOE ticked up year-over-year, and that falls into a reserves, a non-price-related revision. And so it's in that bucket. It's really as a result of higher inflation due to prices, but it doesn't quite fit into that to that price revision category. So there's some interesting nuances. I just want to emphasize the confidence that I have personally and the team has in our reserves process. I'll hand it to Jeff and let him talk that.

Scott Coody :

Paul, this is Scott. I'll jump in real quick and then pass it over to Jeff for the debt question. But the key driver of the shorter lateral length is largely the incorporation of Validus. You brought online in the Eagle Ford, you brought online about 30 wells in Eagle Ford. So that by nature of the drilling configuration there, they're shorter laterals but overall, if you exclude that impact, largely, everything else was close to a 2-mile ladder, which is in line of our previous trends. So that's going to be the big variance there and probably all things equal. You should see that kind of weighting be very similar going forward given the capital plan that we have planned for 2023. Jeffrey?

Operator:

Our next question comes from Neal Dingmann from Truist.

Jeff Ritenour :

Yes, Neal, this is Jeff. Yes, I think if you're speaking to our overall reinvestment rate at a corporate level, that's exactly right. It's just the math and the function of higher costs as a result of the inflation that we've seen and then the lower commodity prices, which we all know have been -- well, certainly on natural gas have been dramatic, but more so important to us is on oil and certainly on a year-over-year basis, the strip would suggest a lower oil price for this year as it relates to last. And so that math just works out to be a higher reinvestment ratio.

Clay Gaspar :

I'd say it's a little too early to kind of really digest all of the lessons learned. The team -- this is really days, maybe a couple of weeks old. We're -- team want to make sure, first of all, there was no one injured. There's no one on location. So that worked very much in our favor. We want to understand the impact to see if there was anything immediate that we had to address on any other compressor facilities with similar designs. We didn't see anything in that regard. The teams are now doing deep investigation in parallel to the real-time fixing. And what I would say is, so far, there's no glaring issues. There's a lot of mechanical parts, a lot of moving pieces. We will learn some things. We will apply some learnings. But I don't think there's anything that really stood out right off the bat that we thought we could improve in the offset operations.

Clay Gaspar :

Yes. I would say middle of March, we should have production fully up and running again about that time. And so it shouldn't bleed into the second quarter. I feel really good about that.

Operator:

This concludes today's call. Thank you for joining. You may now disconnect your lines.

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 quarter and updated outlook. 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 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.

Clay Gaspar:

Thank you, Rick, and good morning, everyone. Devon’s consistent quarterly performance exemplifies the importance of balancing three things

Rick Muncrief:

Thank you, Jeff. Great job. We have covered a lot of good information today, but I would like to close with this key message, and that is that the team here at Devon is delivering on exactly what we promised to do. This is so foundational to our strategy. Our consistency has developed a strong trust for our brand with internal and external stakeholders. We’ve prioritized building a can-do culture and taking care of our people, including the contractors who work for us. We’ve prioritized for share value creation over the pursuit of volumes. And we have rewarded shareholders with market-leading cash returns. We’ve also demonstrated time and again our technical capabilities and operational expertise against all -- across all five of our operating areas by consistently delivering top-tier well productivity and capital efficiencies. Furthermore, I believe we’ve continued to lead and differentiate from peers by establishing a logical, accretive track record of consolidation. The resource assessment successes that Clay referred to with our Lower Wolfcamp in the Delaware Basin and the Niobrara and the Powder River Basin are establishing new sources of supply and inventory. We look forward to sharing additional resource assessment successes in the future. Finally, we’ve continued to take important steps to enhance our business through our marketing and infrastructure strategies that have positioned us to achieve very attractive price realizations across the portfolio and stay ahead of any regional bottlenecks. Overall, it’s been another great year for us, but the best is yet to come for Devon. We are focused on closing out the year with strength and are preparing to build upon this positive momentum into 2023. I will now turn the call back over to Scott for Q&A. Scott?

Operator:

[Operator Instructions] Our first question comes from Arun Jayaram with JP Morgan.

Rick Muncrief:

You bet, Arun. That’s spot on. That’s exactly what we’re saying. That’s correct. That’s the assumption you should make. You bet.

Rick Muncrief:

Yes. That’s a good question. For us, I think the plan that we’ve been implementing over, I’d say, the last 18 months is about what you ought to expect from us in the future. We may have some minor tweaks, Arun, but we feel really good. When you’re a multi-basin operator as we talked earlier, we’re still doing in a couple of our basins, quite a bit of resource assessment, testing new zones, new intervals, things like that. We’ll continue to do that. But as far as the operating scheme, I don’t know that you’ll see a lot of change from what we’ve been employing over the last couple of years. Clay, you want to add anything to that?

Operator:

Our next question comes from Neil Mehta with Goldman Sachs.

Rick Muncrief:

Neil, that’s another good question. From our perspective, I think you’ve heard us be very consistent with our messaging that we will always be opportunistic on transactions that could strengthen our company. We want to make sure that we do deliver the accretion. We’re not waving arms, but we -- actually, it shows up in our income statement over time. And to the point that you made, if it could deepen some inventory, that really is very critical. We’re going to continue holding consolidation, I think, an important part of our overall strategy. That being said, as I mentioned in our prepared remarks, you don’t always find those deals that check every box, and we’re not going to overpay. We’re going to be very-disciplined. And these two transactions work quite well for us. And there could be others in the future, but we’ll wait to see. But we’re certainly proud of what we’ve done and have to give a tip of the hat to our team that brought these over the fence, and they’re great transactions and help us in a lot of ways.

Rick Muncrief:

Yes. I think I’m going to ask Clay to go into maybe some of the detail. But just as I said in our remarks, two-thirds of the increase of capital spending are a direct impact of these acquisitions where you had ongoing rig activity. We had two rigs running down the Eagle Ford on the Validus deal and a rig running in the Bakken on RimRock. So, it comes with capital spend. And so, that’s a big part of it. And I think we broke it down into three other areas for that other third. But Clay, you may want to just share your perspective as well on the increase.

Operator:

Our next question comes from the line of Doug Leggate with Bank of America.

Clay Gaspar:

Yes. Doug, thanks for the opportunity to clarify that. So the upspacing is really relative to, I think, the dark years of the STACK where the industry really down-spaced too much, took for granted the amount of well-to-well interference or maybe isolation and frankly, just over-drilled. I think where we’re at today, we’re seeing phenomenal returns. But as you know, everything changes on a real-time basis, commodity price yields, well costs, realizations. And that constant mix is something we’re evaluating is 3 or 4 or 5 the right spacing specific to Mid-Con. But I think in the broader sense, as we look kind of across the basin and then you move from a midpoint of a $65 price deck to, I believe, we assumed an $85 on the larger account, you also have to reconsider how does that work in other areas. Powder River that is really yet to be defined on how -- what kind of spacing we’re doing. And even some of the deeper potential in the Delaware Basin certainly has significant upside depending on which commodity price you run. And that’s where that really that spot to the -- on the -- the bar on the right really comes in. One additional note on the -- in the Mid-Con area, there’s a lot of running room with gas. And I think that, of course, is a very important consideration as we start thinking about what price deck do you run, what realizations do we have and ultimately, what’s the right economic approach to extract the most opportune value.

Clay Gaspar:

Yes. Is it a little higher than that, Scott?

Doug Leggate:

My follow-up is hopefully a quick one for Jeff. And it goes back to the comment that Rick made about free cash flow in the fourth quarter over 2021. Jeff, you still have about -- looks about an 80% deferred cash tax in that free cash flow number for the third quarter, $1.5 billion. When can we expect to see a more normalized cash tax going forward, and I’ll leave it there. Thanks.

Operator:

Our next question comes from Jeanine Wai with Barclays.

Clay Gaspar:

Thanks, Jeanine. Yes. And you’re referring to slide 18, the bar kind of there in the middle, a total of greater than 4,500 locations. Yes, you got a keen eye, a little more than half of that is in the Delaware. As I think about that kind of light gray box and break that down, by far, most of that is Wolfcamp and Bone Spring, which is, as you know, kind of the really good stuff that we’ve been going after. Certainly, a smaller portion is some Avalon and some deeper other potential, but it’s by far, mostly Bone Spring and Wolfcamp.

Clay Gaspar:

Yes. Thanks, Jeanine. Yes, you’re right. And as we compare quarter-to-quarter, obviously, there’s two ends of that, last year’s quarter to this year’s quarter, and boy, can really get a little bit lumpy. So I think you’re thinking about it right, scaling up, maybe thinking about year-over-year trajectories. And so yes, we will continue to see some nice growth. We said 11% year-to-date on the slide. For the base decline, I would say it’s roughly 30% to 35%, probably closer to 30%. As we continue to moderate the growth, these numbers come down, and that’s a benefit of this -- of the business model that we have. We’ll continue to see that mitigate over time and therefore, making this, keeping our production flat more capitally efficient.

Clay Gaspar:

Yes, coincidentally, really both. But yes, for both.

Paul Cheng:

Two questions, please. The first one is for Jeff and the second one is for Clay. For Jeff, in your presentation, you have an interesting comment saying that the management and effort and the streamlining effort have led to a higher unit DD&A. Can you elaborate about what extent you guys are doing and that could lead to higher unit DD&A? And also what is the benefit that you expect from those efforts? I mean, what were you talking about here? And second point is on the recent bolt-on acquisition in Eagle Ford, is that in any shape or form will impact how you’re going to look at your JV with BP in the area that the -- whether it’s the focus or attention for the companies. I mean, how -- is there any shape or form that is going to have any impact?

Clay Gaspar:

Paul, this is Clay. I’ll pick up on the second question.

Clay Gaspar:

Sorry, go ahead. Sorry, Paul, go ahead.

Jeff Ritenour:

Absolutely. I mean, the work that we’ve done around integration post-merger continues. So, we’re always looking for ways to continue to make the asset base better and how we manage those assets going forward. So certainly, this was a component of our -- of the execution of that integration, and we certainly would expect to see some synergies, albeit minor in the grand scheme of things today, but we’re certainly -- part of our thought process as we rolled out the synergies we talked about post merger.

Operator:

Our next question comes from Scott Gruber with Citigroup.

Clay Gaspar:

Yes. So, this is only the drilling opportunities, but we have additional refracs as well. They’re a little hard to quantify. We’re working on that now. We have some internal numbers around the refracs. And I can tell you, it’s more than just where does it work from a reservoir standpoint. It’s also where does it work from a well construction standpoint. You have to be able to reenter these wells for an economic -- economically and be able to restimulate and really stimulate new rock is the key to success there.

Clay Gaspar:

Yes. I would say, we’re still in the early stages of really rolling that into our portfolio. I would say it’s still in the assessment bucket that I referenced early It could be very meaningful, not just in Eagle Ford, but maybe in other areas as well. And so the quantity that we’ve done this year, and I expect for next year, is relatively small. As I’ve mentioned, it’s finding the right recipe. What was the original stimulation in that well? What was the stimulations in the offset well? What’s the spacing to the offset wells? What’s the casing construction of that well? And does it lend itself to the right recipe so that we can reenter, properly stimulate, hopefully, charge that new rock and, therefore, really get the bang for the buck. What I can tell you, the early results are we’re very encouraged. I think we’re finding the right recipe, but it’s too early to really lean in too hard just yet.

Neal Dingmann:

My first question is on your Delaware transportation specifically. Could you all speak to the continued Delaware takeaway? And then also how you all are protected from the Waha price volatility that we’ve even seen recently?

Neal Dingmann:

Great answers. And then my second question is on your natural gas plant, specifically. Could you all give us some more color maybe on that Delfin LNG partnership, how you might see this advancing and then other potential similar, I’d call, nonbinding type agreements or opportunities going forward?

Operator:

Our next question comes from John Freeman with Raymond James.

Clay Gaspar:

Thanks for the question, John. This is Clay again. I would say more from the appraisal. We think about the work that we’re doing in a lot of these horizons that are just not quite defined on downspacing, what’s the right spacing test, maybe even vertically. Is there two landing zones there or is there three landing zones in some of these intervals. And then I think about some of the stuff that’s a little bit further afield, say, in the Powder, there’s a lot more opportunity there to bolt on to that number from the appraisal standpoint. Any additional -- just to be clear, we don’t have any assumptions on future acquisitions or any additional bolt-ons in any of these numbers.

Clay Gaspar:

Yes. Just think about it kind of similar to ‘22, kind of a similar runway.

Matthew Portillo:

Just to start out a question around Q4. It looks like the market is a little bit spooked on the guidance. As we look at the well data in the Permian in particular, your well results look extremely consistent on a year-over-year perspective, but curious as you guys look at the data, how you’re feeling about your productivity trends. And then, if you are seeing fairly consistent well results, just curious if there’s anything to take into account regards to till timing during the fourth quarter that might have led to some of the guidance shaking out in Q4.

Matthew Portillo:

And then, I guess, a follow-up question, Clay, maybe on the STACK. You guys have started the upspace program here with Dow. Looks like some impressive initial rates. Just curious if you could provide some context around well performance with the upspace completion design. And then additionally, just a view on midstream infrastructure as the asset starts back on growth, should we expect further midstream build out either on a G&P perspective or some marketing to move gas further south to accommodate that growth in ‘23 and ‘24?

Operator:

Our next question comes from Kevin MacCurdy with Pickering Energy Partners.

Clay Gaspar:

Yes. I would say roughly so that 65% -- or 65,000 BOE a day is about -- what would be for the quarter. So, I appreciate the acknowledgment of the third quarter, sometimes that can get lost. The teams worked exceptionally hard to continue to perform, and we’re really, really pleased with that. The Williston as we take over on any of these acquisition deals, no doubt about it, there’s going to be handoffs and little bumps in the road. There was a particular pad that came in. We had some delays. And as you know, when you’re running kind of a subscale activity, just a few days or a week of delay can manifest into a larger delay when you’re really trying to pick up and lay down equipment. And that beat us there. And so, we had a little bit of a transition issue there. But I think we’ve got the team up and running now, feel really good. I’ve bragged on many of earnings calls about the Williston team in particular, have tremendous regard for them and faith in their execution. And again, this is -- integration is not necessarily normal core competency. We’ve taken it as one that we need to be exceptionally good at this. And I’m really proud of the results we’re seeing around the organization from HR, from the IT department, from the accounting group, everybody coming together to really bring these assets in and ultimately extract the optimum value for the shareholders.

Operator:

This concludes today’s Devon Energy Third Quarter 2022 Earnings Call. Thank you for your participation. You may now disconnect your line.

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 quarter and updated outlook. 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 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.

Clay Gaspar:

Thanks, Rick, and good morning, everyone. As I reflect back, not just on the quarter, but the last 18 months since we've closed our merger, I'm very proud of what we've accomplished. Last year at this time, we were well past the hard work of organizational design answering the who, but still very deep into the systems process and culture building that's incredibly important to answering the how of running the company. In some ways, we're rebuilding the engine while we ran the race. This year, we're continuing with the never-ending challenge of improving systems, processes and culture, but we're also keenly focused on external factors like inflation and supply chain uncertainty. While these challenges are real and something we dedicate a lot of attention to, I'm also fully confident in our team's ability to once again differentiate Devon from the pack and execute on an exceptionally high level. The second quarter results are a perfect example of this product related to this focus. As a summary of the operating results displayed on Slide 16, which showcases our solid production beat better-than-forecasted capital efficiency and the expansion of our per unit margins to the highest level in more than a decade. I know it can be a bit mind numbing when the team makes these results look as easy as they have. But listen, every well in the portfolio, average 30-day IP for the entire company of 2,900 BOE per day per well, $60-plus field level margins and a reinvestment rate of 22% are incredibly impressive when you put them into historical context. The perpetually strong results that we've delivered since the merger between WPX and Devon is simply an outflow of 3 key factors

Richard Muncrief:

Thank you, Jeff. Great job. I'd like to close today by reiterating 4 key messages from our call

Operator:

[Operator Instructions]. Our first question comes from Jeanine Wai from Barclays.

Clay Gaspar:

Jeanine, this is Clay. I'll take this one. The strategy remains the same. We do have categories of the strategy related to growth. The 0% to 5% is kind of one of the metrics. But if you refer back to Slide 3, we also focus a lot on free cash flow. On Slide 16, we talk about some of the margins. And so now that the focus is not just how much capital are we spending or how much production are we making. It's the flow-through result. And so while we're really excited about the margins today, and we're really excited about the 22% reinvestment rate, we have a stated goal to be somewhere below 70% on that reinvestment rate. So there's a lot of flexibility on built in and allowing us to continue the strategy even with the headwinds of the very real inflation we're seeing today.

Jeffrey Ritenour:

Yes, Jeanine, this is Jeff. Thanks for the question. Yes, the biggest thing that happened for us here at the quarter was we were blacked out the bulk of the second quarter as it relates to our share repurchase program, given the RimRock transaction that we've talked about. So we didn't quite get as much done as we would have liked to, that left us with just over $800 million of authorization still available to us. And so we felt like we've got plenty to go execute on here over the next quarter in the back half of this year. And of course, if we make as much progress on that front as we hope to hear in the near term, we'll absolutely go back to our Board and reload that authorization to accomplish more share repurchase. It's a critical component of our cash return strategy. And as Clay mentioned, we're very much focused on per share growth on all line items.

Arun Jayaram:

My first question is if we look at first half activity, perhaps for Clay. You guys tried to sells 131 wells, about 80%, a little bit over 100 in the Delaware Basin. We are seeing a little bit more spud activity or drilling activity in some of your other basins. So I was wondering if you could give us a sense for the 3Q TILs of 100, maybe a little bit of help on the mix on a basin level, just broad mix?

Arun Jayaram:

Great. That's helpful. And maybe one for Rick. Rick, you guys announced a couple of things on portfolio renewal over the last quarter, RimRock plus some of the acreage trades in the Delaware I was wondering if you view kind of RimRock as kind of a one-off just opportunistic? Or is this part of a broader strategy, call it these niche acquisitions to address portfolio renewal?

Operator:

The next question comes from Doug Leggate from Bank of America.

Richard Muncrief:

Yes. I'd say this, Doug, as we said in our prepared comments, it's a little early for us to give you granular detail. We're going to continue to stick with our strategy of maintenance type spending level. You talked about the midstream asset spending, we do have some expansion. We have the joint venture. We're going to be building our third train. That JV is going very, very well. We've got the 400 million a day cryo plant is full, and so we'll be working with our partners there to expand that to handle our gas production there. But still too early for us to be laying out any 2023 numbers. And I don't know if Clay or Jeff want to weigh in on that, but that's kind of where we're at right now, Paul.

Richard Muncrief:

Yes. Doug, that's a great question. We get it quite a bit. And I can tell you, when you're looking at a $1 commodity price for gas, it's -- I think you're really -- I think people listen to us more than they did back when it was a $3.50 gas price, and we talked about the diversity that we enjoy with this portfolio that we have. And so for us, I don't know that you're going to change -- you'll expect to see us change our capital program allocation because recall that in our Delaware Basin, we do have a great deal of gas production there. So really some wonderful returns. We do have 4 rigs running here in the Anadarko Basin to your point. We're seeing some great returns there. And the one thing that we want to do is a little bit more assessment type work there, some ideas that we have. And so we'll be very measured with that. But it's a wonderful asset. We have a great acreage position. We have a great joint venture partner, which we talked about with Dow. And the JV is going very well. We're generating some phenomenal returns with it. We're going to be very measured, very thoughtful about it. So I wouldn't expect us to have significant changes in our capital allocation mix.

Scott Hanold:

Yes. Just -- my first question is going to be around your view of intrinsic value. Can you give us a sense of how you get your arms around what the Devon's intrinsic value is. How aggressive will you get on the stock buybacks? And as part of that discussion, it would be interesting to hear your thoughts on your 50% variable dividend payout ratio if there is some flexibility to move higher than that? Or is really just keeping optionality for buybacks and maybe bolt-on another kind of M&A activity, the continued plan?

Scott Hanold:

That's great color. And my follow-up question is you talked about looking at opportunistic activity, I mean with the bolt-ons and RimRock. But I think the term you used for that is portfolio renewal. Can you give us a sense of how you think about portfolio renewal versus acquisition per scale? Do you -- is Devon a right scale for -- to be a very efficient company? Or do you think there's still some advantages of rather than just buying stuff for renewal just for scale to have better cost efficiency on a per unit basis?

Operator:

The next question comes from Neal Dingmann from Truist Securities.

Richard Muncrief:

The shareholders we talk to and we frequently engaged with, the feedback we get continues to be similar to ours, and that is focused on a per share approach. And so when we talk about growth, it's a per share growth. And so fundamentally, unless we have shareholders, numerous shareholders that come in and say, look, we absolutely -- we do not like these big dividends. We do not like your share repurchase program. We want you to go back to a growth model. Until we see that, I see no reason to change our strategy. And this is a strategy that we didn't -- we've really not tweaked our strategy since we laid out the merger announcement in September of 2020 and nearly 2 years ago. And so I think we've been very consistent. We did -- a few quarters back, we did talk about bumping our fixed dividend and we also talk about the -- adding the share repurchase option. And those are things that really just solidified our cash return model and I think as commodity prices strengthen, we saw it just -- it really adhered us to our shareholders when you could go across with all those options and deliver across the board. So to go back and completely change our strategy, I don't know, it just seems like a real long put for us right now to -- and we're certainly not getting that feedback from our investors.

Clay Gaspar:

Yes. Thanks for the question, Neil. It's -- I relate the federal land, it's kind of like work in international stuff. You have certain rules to live by. There's really good things about it, and there are some challenging things about it. I think specifically with the federal lands is you need to have a long view on a program. You need to be 2 years out ahead. You need to plan for your right of ways, you need to plan for your tie-ins, you need to plan for all the contingencies and that's how we treat it. So happy to report. We still have 600-plus permits out ahead of us. That gives us plenty of runway. We're working very diligently with the local BLM office. I think they have a better understanding of what D&C is asking them to do, great hard working people that want to do their jobs well. And we work really hard to make them successful at helping us do what we need to do. So I would say, so far, we feel good about the trajectory. There's always the concern of something changing. We'll react to that then. But I think most importantly, is having a long vision, a road map that allows us to stay out in front. As Rick mentioned earlier, having a diverse portfolio, having assets on the Texas side of the basin, having assets in other areas around the country is only accretive to the story. Currently, we're allocating quite a bit of our total capital to the Northern Delaware because of the amazing returns that we have there. And the great work that the team does allowing us to execute on it.

John Freeman:

The Delaware well results continue to look quite good, but it is interesting that the lateral lengths are a good bit shorter through the first half of the year than what we've seen the prior couple of years. And obviously, you all highlighted the Stateline acreage trade that you all did, which caught up a good bit of the acreage highlighted to do some more extended reach laterals and, I guess, I'm just trying to get a sense of kind of, I guess, a, what has kind of driven kind of the first half activity to be maybe on the shorter side on the laterals. Again, good results, but the laterals being a good bit shorter than what we've been accustomed to and maybe how to think about that going forward if we'll kind of move back toward that 10,000 type lateral length or better?

John Freeman:

And then a follow-up question for me. In the past, you've -- you talked about one of the things that you have used to try and combat cost inflation as sort of your size and kind of consistent activity levels in terms of being able to look out and maybe layer in some longer-term sort of contracts for both materials and services. And I'm just curious if we could get some feel for kind of what the environment is at the moment in terms of service providers kind of willingness to offer longer-term contracts through 2023 or if it's just too cost prohibitive to kind of do that at this point?

Operator:

The next question comes from Neil Mehta from Goldman Sachs.

Richard Muncrief:

Yes, Neil, great question. I guess for us, we think that just fundamentally, OPEC, we'll see what they come up with. But they probably may handicap a little bit of the concerns around a possible recession that could impact demand some -- somewhat. I don't think it's going to be very, very large. If they were to bump there, let's say, Saudi specifically, if they were to bump their productivity. I don't think it would be a large bump because I think in the back of their minds, they're looking at a lot of data like we all are, right? And so they're going to be -- I think they're going to be very measured. The rest of OPEC, I just think, quite honestly, I think are going to be very, very challenged to getting more close their quotas. That's been, I think, well represented. So for us, when we think about maybe a slight uptick in Saudi's production, maybe even the UAE, but I don't think it's going to be that strong. You see continued discipline. You do see some growth here in the lower 48, but it's still a disciplined approach. China is -- there's a point in time when you will see that demand, I believe, increase as they started reopening. In our mind, demand is going to be strong. And I think demand is going to -- net-net is you're going to start -- you'll still see some demand growth until we see prices -- I think WTI north of 120. That's kind of what we thought the first time and it pulled back and it could have been just circumstantial. But -- so we'll see. But I think for us, we're very constructive on the commodity price environment. That's both on the crude side and then on the gas side, too. I've been a little surprised that gas didn't pull back a little harder and stay, but it's -- I think we've talked about it with our team, just fundamentally, you do not want to be short at gas in this world. And I think that at that point-driven, whether it's whether it's a Uri storm or type storm or some of the geopolitical things, you just do not want to be short at gas. That's an uncomfortable place for governments and utilities and the greater society. So we're very, very constructive. I think for us, we just -- Neil, we're very pleased with our execution. We're staying on top of the supply chain the best we can, and it's, I think, going well. We've made some really strong moves on -- in the marketing front, both on the gas side and the crude side to ensure, in my mind, very consistent reliable flows to the market. So I think we've done what we need to do. And I guess the takeaway for us is that we still are constructive on demand, both on the oil and gas side.

Richard Muncrief:

Yes. I think -- let's start with crude. I think for us, we are really -- there's ranges of estimates out there. So we think about the balance of growth throughout the back half of '22, and we're probably a little more conservative than what some of the estimates are. And so in other words, we're not as bullish on U.S. growth as some will be for the back half. And there's a number of reasons there. I think for the -- as far as the maturation where we're at with the lower 48 plays, fundamentally, I think you've seen places like the Bakken, the Eagle Ford, in particular, where you've seen volumes are hanging in there, but you're really not seeing a lot of growth. I think we did see an uptick in the Eagle Ford, but it's come back some, but I think both of those basins will be challenged to grow much. I think you have plays like the DJ and the Anadarko. We're not in the DJ, but that's a place we'll watch. I think in places like -- especially like the Anadarko, gas is going to be -- you can see some growth there. But it's going to be, I think, in aggregate, going to be somewhat moderate. And so it all comes down to the Permian. And I think the Permian will continue to be the only basin that grow substantially. But even with the Permian, I think you'll start seeing impacts of things like the supply chain pinch and others. I think many of the private operators have been the ones that have driven the growth. The first -- I really say about the last 12 months. And so I think that's going to moderate a little bit. And so we'll see how it all plays out. You'll still see growth, obviously, but I think it's going to play out a little bit. It may not be quite as much growth as some people have forecasted. We'll see how it plays out.

Matthew Portillo:

Perhaps a question for -- a question for Clay around delineation in the Permian. You've had some pretty outstanding results in the Bone Spring. I was curious how your thinking on that play has evolved as you work the asset both in New Mexico and at the Stateline and what that might mean for inventory expansion over time.

Matthew Portillo:

Great. And then just as a quick follow-up. Last quarter, you highlighted the potential savings from vertical integration on your sand mine expansion in the Permian. I was just curious if you could give us updated thoughts on potentially expanding this operation beyond the Permian and additional mines that might be able to be developed going forward to continue to lower your cost on development.

Operator:

The next question is from Kevin MacCurdy from Pickering Energy Partners.

Clay Gaspar:

Thanks, Kevin. I would say it's really pretty early. We are just taking over some of the operations now. Best thing to do is a whole lot of consistency to make sure we don't having any of the wheels fall off in the process. But there's certainly techniques. I would say, generally speaking, completion designs are roughly similar. I think we'll see some tweaking. I think certainly, our supply chain efforts will help right away in kind of the next round of wells. But I want to be real clear. We are also taking this opportunity to learn. We can learn from everybody, RimRock is fighting a good fight just as everyone else in our industry is doing. And so every time we either look at one of these deals or when we were able to actually consummate a deal, we take it as an opportunity to step up our own game as well. And there's things mainly on the facility side, some nuggets that we've already picked up, and we're exporting to the rest of the basin from this transaction.

Clay Gaspar:

Yes. I would just say directionally, same strategy, so 0% to 5%. When we come off that zero or low end growth, know that it takes time just to move that. So I would say where we stand today consider us on the low end of that 0% to 5% range. As you see in our quarters, we'll have quarters that are a little higher and a little lower, but when you zoom out a little bit and you draw a line through it, we're well inside the strategy, and we hope that, that -- we plan for that to continue into '23.

Operator:

Thank you all for joining. This now concludes today's call. Please disconnect your lines.

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 quarter and updated outlook. 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 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.

Clay Gaspar:

Thanks, Rick, and thanks to those listening in on our call today. As you can see from the results we issued last night, our team delivered another round of impressive operating results. I want to stress to you that I don't take these regular accomplishments for granted nor should it diminish the valiant work that the team does to make these consistent deliveries look easy. This is a technically challenging business that continues to get harder every day. I believe that our recipe for today's success will continue to deliver in the future. The foundation of that operational success is built on a high-quality portfolio. That foundation is brought to life by incredibly thoughtful and hard-working people. And that team is guided by a business model, as articulated on Slide 3 that provides a steady course for them to drive their efforts towards. Once again, this quarter, strong well productivity across the portfolio drove production to exceed the midpoint of the 1Q guide, while steady operational improvements allowed us to mitigate additional inflationary pressure and keep our cost structure in line with the full year plan. This comprehensive execution across all phases of our operations allowed the higher commodity prices to pass directly through our field level margins and generate the highest level of cash flow for Devon in nearly a decade. Now let's turn to Slide 13, where we can discuss our franchise growth asset in the Delaware Basin. In the first quarter, net production from the Delaware increased 27% on a year-over-year basis. This volume growth was driven by 52 high-impact wells brought online that were diversified across targets in the Avalon, Bone Spring and Wolfcamp formations. In aggregate, these wells achieved average 30-day rates of 2,800 BOE per day with an average oil cut of over 60%. At an average completed well cost of around $7.5 million per well, the overall returns from this program are outstanding with many of these wells on track to pay out in less than a year at today's strip pricing. Turning to Slide 14, another highlight associated with the Delaware activity was the improvement in operational efficiencies and margin expansion we delivered in the quarter. Beginning with the graph on the left, we continue to achieve efficiency gains across each phase of our operations. In fact, in the most recent quarter, our drilled and completed feet per day metrics continued to improve to 85% and 135% respectively from just a few years ago. A great example of this progress is that team drilling our fastest well ever in the basin during the quarter with a spud to rig release time of only 9 days. At this point as a point of comparison, I can remember evaluating the 2015 acquisition that brought WPX into the basin with spud to rig release times of greater than 40 days. Completion efficiencies also steadily advanced with our best results occurring in the Upper Wolfcamp development that reached a record high pace of 2,400 completed feet per day. These accomplishments clearly demonstrate the great work our team along with our service company partners have done to drive improvements across the entire planning and execution of our resource. Directing your attention to the right side of the slide. We also effectively control lease operating expense in the quarter by keeping our per unit LOE costs essentially flat on a year-over-year basis. Our consistent operating plan, leverage of technology, enhance purchasing power and relentless focus on margin allows us to manage and offset rising costs and maximize the value of this production in this inflationary environment. As you can see this strong cost performance resulted in significant margin expansion compared to both the previous quarter and on a year-over-year basis. As I look ahead to maintain this high level performance, a top priority for us is to continue to stay ahead of inflationary pressure and supply chain disruptions. As the market is tightened, we’re experiencing substantial cost increases in raw materials, continued labor shortages, and uncommon scarcity across numerous products and services. We combat these challenges with thoughtful upfront planning, technology, consistent activity levels, and through bulk purchasing power we possessed doing due to our operating scale. Our effectiveness thus far as evidenced by our 1Q upstream capital spending coming in at only 24% of our full year. As we look as our full year guide. As I look forward to the rest of the year, I have confidence in our team and process is to mitigate our exposure to supply chain disruptions and out of out control inflation. We will continue to watch this closely, but if these trends continue, our capital spend could gravitate towards the top half of our guidance range for the year. Turning to Slide 16, a catalyst that will help us combat higher cost environment is the recent commencement of a company owned sand mine on the surface acreage we own in loving county. This mobile sand mine is the first of its kind in the Delaware Basin and is expected display up to 25% of our profit requirements in the basin this year. In addition to providing a certainty of supply, this mine could save us up to 200,000 per well relative to the rising spot prices we are experiencing across the basin as activity picks up and sand supply is tightened. Equally important, this mine also has significant environmental and safety benefits due to the need for fewer trucks on the road. And it eliminates the combustion related emissions associated with drawing the sand that occurs in normal mining processes. Finally, controlling this critical baseline of supply in this market is incredibly valuable to operational certainty. This creative solution to the current supply chain crunch is another benefit from an investment we made of a purchase of 15,000 acres of service land in the Stateline field in 2018. With the early success from this project, we are excited about the potential to expand this concept to other areas of our portfolio with opportunities already identified in both Anadarko and the Powder River Basins. This innovative approach to sourcing sand for our completion operations serves as another great example to our team’s drive for continuous improvement. Moving to Slide 17. While the Delaware Basin is clearly the growth engine for Devon, we also have several high quality assets in the top U.S. resource plays. The teams that support these assets are doing an incredible job of working to drive capital efficiencies, optimized base production, keep operating costs low and steadily improving our environmental footprint. As you can see by the slide by executing at extremely high level on these critical objectives, these assets are on pace to grow cash flow by about 20% this year to around $2.5 billion at today’s pricing. I’m proud of what these assets are delivering, and I appreciate the team’s hard work and efforts that go into fulfilling this important role within our portfolio. And with that, I'll turn the call over to Jeff for financial review. Jeff?

Rick Muncrief:

Thank you, Jeff. Great job. I’d like to close today by reiterating a few things. Number one, the execution of our strategy is delivering impressive financial results you’ve just heard that. Number two, there’s no change or disciplined game plan in 2022. Number three, we are rewarding shareholders with record high cash payouts. And number four, we’re confident we can continually and sustainably deliver this kind of performance for years to come. Lastly, I’d like to reiterate once again, how proud I am of this team, the results they are delivering and the reliable energy we provide our great nation. The energy crisis we’re experiencing in certain regions across the globe is a stark reminder of how critical it is for the U.S. to have a clear and consistent energy policy to ensure our nation’s security and global leadership. Oil and natural gas will remain a core source of energy for decades to come. And this needs to be acknowledged and accepted with any energy transition policy discussions. This transition is not an event in time, but rather a multi-decade endeavor that will require enormous amounts of energy from all available sources to meet the world’s growing demand. Energy policy matters and if we misstep physics and economics will defeat platitudes and untethered ideologies over time. At Devon, we’re committed to doing our part by showing up to work every day to responsibly produce low cost, clean and reliable energy. We’re also dedicated to bettering the communities in which we live and work by supporting investments in public education, healthcare, infrastructure, and by providing high paying jobs to American families. I will now turn the call back over to Scott for Q&A. Thank you.

Operator:

Thank you. [Operator Instructions] Our first question is from Arun Jayaram of J.P. Morgan. Your line is now open. Please go ahead.

Jeff Ritenour:

Hi, Arun. This is Jeff. Yes, the short answer is absolutely, yes. And so as you know well, we continue to kind of evaluate each quarter the financial framework that we've laid out to The Street and obviously discussed it in great detail with our Board. Our first priority is always to make sure we feel comfortable with the leverage in the balance sheet. We're in great shape there. As I mentioned in my prepared remarks, we've got $400 million we'll take out later this year and then another $600 million into next year. And frankly, if you look beyond that in 2024 and 2025, we'll have the option to take down another $1.5 billion of debt if we so choose, as we work our way out into the future. But right now, given the strength that we have with the balance sheet, we're really focused on delivering on that fixed variable dividend commitment that we've made. And then beyond that, we're incredibly excited to buy back our shares given the current level that we see and kind of how we're trading not just versus our peers, but versus the broader market. We think there is a real opportunity to create some real value by buying back our shares. And so you're going to see us continue to lean into that as we work our way through the year and hopefully our track record is a pretty good indicator of our behavior, which is each quarter we've continually added to that and added to the capacity and our ability to go after that.

Jeff Ritenour:

Yes. You bet, Arun. I think you and I discussed this question on the last quarterly call as well. Just as a reminder with – currently our setup and with our production out of the Delaware, about 50% of our current production in the Delaware we have firm takeaway that we own and control and move those volumes out of the Delaware Basin to the Gulf Coast. With the remaining 50%, about half of that, we actually sell to counterparties on term sale deals that actually have firm takeaway capacity as well out of the basin and then the remaining 25% of our production today actually sits there in basin. And so that's the current construct. For that, we do share the concern that the broader market does around takeaway for gas out of the basin as you move into 2023 and 2024. So we are actively evaluating different opportunities to move more of our gas out of basin if the value proposition makes sense as we work our way to that. From a price standpoint, again, 50% of that production is getting Gulf Coast pricing. And then the other 50%, the way we've been trying to manage that and mitigate any impact to differentials is through our hedging program. So you'll see in our hedging disclosure that we outlined last night, we have a significant amount of our production that's in basin, get in-basin pricing. We've actually hedged that for this year and well into 2023.

Operator:

Our next question is from Neal Dingmann of Truist Securities. Your line is now open. Please go ahead.

Rick Muncrief:

Well, I still think – I think we've been rewarded to degree with our dividend framework, that strategy and the execution of that. I believe that investors are going to continue to reward us for the predictability, the transparency of what we're doing. But I still think, fundamentally, that when you look at – and I mentioned this in our prepared remarks is that we're fundamentally undervalued when you start looking at the multiples and the returns people are going to see from us over the next several years. And I think that's something that – it's not just us, but I think it is especially us, but it's not – we're not the only company. I think there needs to be just a fundamental change of thinking with all of us on what our expectations are when we consider our multiples relative to virtually any other sector in the broader market and I think it was a great setup. We're going to – you heard Clay give you some ideas on some – not only ideas, real examples of what we're doing from a creativity standpoint, addressing supply chain issues. You've heard Jeff talk about some things we've done on the gas takeaway. So many of these challenges, we always think that we're going to be a step to – ahead of the competition and it's not only the competition, but issues that are coming our way that could be problematic for us. So I think that all we need to do is just keep being ourselves and keep delivering, being transparent, and I think it's going to work out just fine. Clay, do you want to add anything else?

Neal Dingmann:

Yes, agree guys. I don't think your low-cost capital is even being considered as well. But lastly, just on the second question, could you talk about maybe asset allocation specifically, Clay, you talked about the repeatability. I'm just wondering given the entire move of the natural gas strip, any consideration of allocated more towards Anadarko? Or still is that just not competing in again? I know how good the Permian returns are. So again, it's a nice sort of challenge to have. I'm just wondering how – any outlook in that over there?

Neal Dingmann:

Well said. Thanks guys.

Operator:

Our next question is from Jeanine Wai of Barclays. Your line is now open. Please go ahead.

Rick Muncrief:

Good morning, Jeanine.

Jeff Ritenour:

Hi, Jeanine. This is Jeff. Yes, thanks for the question. Yes, absolutely. You nailed it and highlighted that we've got a significant portfolio of gas, obviously, just under a Bcf a day. So it's something we think a lot about. We do think there's going to be opportunities to capture a better realized price for our gas longer term given the LNG dynamic. So that's something that we are actively evaluating and thinking about. Don't have anything to announce today, but certainly something you'll hear more from us about in the future as we get further into those opportunities and determine what makes the most sense.

Jeff Ritenour:

Yes, you bet, Jeanine. No. I mean, fundamentally, we want to get more and more cash back to shareholders. I think we've been pretty clear on that with our framework and finding ways to do that, creative ways to do that from quarter-to-quarter. So I think that will continue to be the mantra for us and the behavior that you'll see us pursue. From my seat, I'm never fussed with building cash. So I'm always happy about that and certainly gives us a lot of optionality and flexibility as we execute our game plan. But certainly, we're cautious given the inflationary environment we're in. Sitting on cash is probably not the most productive thing that we could do. So we're always actively evaluating different opportunities in different ways and debating those ways with the Board as to how to get more and more of that cash back to our shareholders. So that – I think you'll continue to see our framework evolve over time and – but certainly will be consistent with what we've outlined in the past.

Operator:

Our next question is from John Freeman of Raymond James. Your line is now open. Please go ahead.

Rick Muncrief:

Good morning, John.

Clay Gaspar:

Hi, John. It's Clay. Thanks for the question. Yes, the answer is we do need to think about things differently. I can think of a number of kind of slight modifications to our normal course. And the first one that comes to mind is I love innovation. I love change. I love what's the next, what's the 1.1, what's the 1.2. If that 1.2 is working, how do we get to 1.3? What we've talked about internally here is the necessity out of being a little bit more sticky in our designs. As we think about facilities design is a perfect example, we may have that great next idea. And we just put that into practice and some – a brilliant mind from the field said, hey, if we just did it this way, be even better. In this environment, we need to be a little bit more sticky with our designs. And what I mean by that is working with our supply chain, telegraphing not just the normal 3 months or 6 months lead times but 9 and 12 months. So what you end up seeing is, and you don't see this on the external, but internally, instead of a 1.1, we may wait for a 2.0 innovation to make that next change. That's just a cost of the current situation. The other thing we're being very cognizant about our suppliers and very importantly, our supplier suppliers, one of the great questions I love asking of our partners is what's your potential supply constraint – supply chain constraint and how are you mitigating those? And so as we think about aligning with partners that have more and our service company partners who I'm talking about, as they have more sophisticated kind of vision into their own supply chain, that gives us greater confidence in aligning with them because if they fall short, that means we fall short and the whole thing falls apart. So there are several examples that we think about – as we talk, rig contracts are always a great proxy. As we think about interfacing with our rig contractors, we ask what's the well-to-well contract look like, what's a 6 month, 12 month, 24 months look like? And by talking company to company, you'll kind of get a feel for their – essentially their supply/demand curves internally and we'll make decisions on who do we think can complement one versus another. And what we're actually trying to do is blend a mix of short-term, mid-term and long-term contracts, so that we stay current in the market and also mitigate significant run-ups in a short period. So, there's a lot of things that are probably more normal course. In this part of the supply chain, this kind of hyper concern around supply chain, I think everything has kind of just dialed up to 11 about how we think about these things and really try and protect outside, downside.

Clay Gaspar:

Yes. Thanks for the question. This is just an example project of a lot of things we have kind of under the radar that we're working on to take a little bit more control and make sure that we have at least a baseload of supply. Sand is one of those things that nobody worries about until it's an issue and then it's a major, major issue. And so, owning the surface as we did kind of keeping an eye on the horizon, what everyone else is doing, we saw an opportunity here. And it's still – we're still – we've got start-up issues. We're still running this thing, just ramping up the activity. And so, I would say it's a little too early to talk about significant expansion, but really, really pleased about this as a project. As I think about – in the ESG world, I think about projects that are environmentally better, that are safer, that saves money that just absolutely do the right thing and then help us from a supply chain perspective. This was one that checks all the boxes. So really excited about it. As we talk about other basins, it's different in each basin. It's a pretty unique situation for us to own so much surface right in the middle of the heart of one of our biggest fields. We don't have that luxury in other areas. So you look at it a little bit differently, partnering with landowners or even partnering with sand contractors to make sure that we have that kind of this ability very close to our – the heart of our operations and still achieve at least most of the benefits associated with it.