DVN - NYSE

Hello, everyone, and welcome to Devon Energy Third Quarter Earnings Conference Call. At this time all participants are in a listen-only mode. This call is being recorded. I would now like to turn the call over to Mr. Scott Coody, Vice President of Investor Relations. Sir, you may begin.

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.

Thank you, Scott. It's a pleasure to be here this morning. We appreciate everyone taking the time to join us. For today, I plan to focus my comments on the trajectory of our business for the remainder of 2023 and highlight the steps we're taking to further improve capital efficiency as we head into 2024. Now let's start with a brief review of our financial and operating performance. In the third quarter, Devon delivered a production per share growth rate of 10% year-over-year. This strong growth rate was fueled by our franchise asset in the Delaware Basin, accretive acquisitions and an opportunistic share repurchases over the past year. On a barrel of oil equivalent basis, our total volumes were within the guidance range, but oil volumes were slightly softer due to select well performance in the Williston coupled with minor infrastructure constraints in the Delaware. We will cover the Delaware in greater detail later in the call, but these constraints were temporary and have a visible pathway to correction with the industry's ongoing build-out of infrastructure. Turning to capital for the quarter. With our disciplined plan, we've kept reinvestment rates to just over 50% of cash flow. This resulted in our free cash flow more than doubling versus the second quarter, and we rewarded shareholders with a 57% increase to our dividend payout. In the fourth quarter, we expect Devon's production to be around 650,000 Boe per day of which oil is expected to approximate 315,000 barrels per day. Now as a reminder, we dropped our fourth frac crew in the Delaware midyear to replenish our DUC inventory and the impact of this lower completion activity will lead to a minor decline in our production versus the third quarter. We've also modeled in the effects of project timing and weather impacts, some of which we've already experienced. However, we do expect our financial performance in the fourth quarter to be very strong with operating margins set to expand and free cash flow to be quite robust. Overall, the fourth quarter is set up to round out another successful year financially for our company. And while we have certainly faced some challenges this year, we're on track to deliver one of the best years in our 50-plus year history in terms of returns and free cash flow generation. Importantly, as we head into 2024, our focus remains the same. We intend to deliver growth on a per share basis and maximize free cash flow generation, while balancing the need to appropriately reinvest in our business for the future. To achieve these objectives, we have incorporated our learnings over the past year, pushed service costs lower and sharpen our capital allocation to deliver a step-change improvement in well productivity and efficiency. Now on Slide 8, we outlined the key attributes underpinning our improved outlook for 2024. First and foremost, with continued volatility in commodity pricing, we believe it is prudent to conduct – construct a capital plan with consistent activity levels to maintain production at a level around 650,000 Boe per day with oil at approximately 315,000 barrels per day. With ongoing macro uncertainty and with the ample spare capacity that OPEC+ possesses, we have no intention of adding incremental barrels into the market at this point in time. This disciplined approach reflects our commitment to pursuing value over volume and shareholders will benefit from our high-graded slate of development projects designed to enhance capital efficiency and returns on capital employed. To deliver this production profile in 2024, we anticipate a capital investment of $3.3 billion to $3.6 billion. This level of spending represents an improvement of 10% compared to 2023, and we expect to fund this program at pricing levels below $40 per barrel. In summary, we see delivering flat production for 10% less CapEx. Now turning to Slide 9. Our improved capital efficiency in 2024 is driven by concentrating more than 60% of our spending in the Delaware Basin. Our plan will shift a higher mix of activity to multizone Wolfcamp developments in New Mexico, which is the core of the play as infrastructure constraints have eased over the past and will continue over the coming months. We also plan to high-grade capital activity across other key assets in our portfolio. This includes limiting Williston Basin activity to only our highest impact opportunities and decreasing activity – appraisal activity in the Eagle Ford. With this refined capital allocation, we expect to improve well productivity by 5% to 10% in 2024, anchored by our franchise asset in the Delaware Basin. And lastly, we expect our capital efficiency to also benefit from improved service costs as contracts refresh over the next few quarters. Now with this operating plan in 2024, we are positioned to deliver free cash flow growth of around 20% in 2024 at $80 WTI pricing. As you can see on Slide 11, with this strong outlook that translates into a uniquely attractive free cash flow yield of 11%, which is up to 3x higher than what the broader equity markets can offer. Simply put, this is one of the most critical aspects of the Devon plan. On Slide 12, with the stream of free cash flow, as we've done in the past, we plan to target a cash return payout of around 70%, which is in line with our average annual payout to shareholders since we unveiled this industry-first model in 2020. A key priority heading into next year is to continue to grow our fixed dividend. We believe the certainty that comes with a fixed dividend is valued by shareholders and is better capitalized within our equity price, especially if the yield is competitive with that of the broader markets. With the remainder of our free cash flow, we will stay flexible as we always have been by judiciously allocating toward the best opportunities, whether that be increased stock buybacks, variable dividends or taking additional steps to improve our balance sheet. However, given our current stock price, we expect to pursue buybacks at a level that will most likely result in our variable payout being below the 50% threshold in the near term to capture the incredible value our equity offers at these trading levels. And with that, I'll now turn the call over to Clay for a rundown of our recent operational performance.

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?

Thanks, Clay. I'll spend my time today reviewing our financial performance in the third quarter and discussing our cash return approach for the future. In general, revenues and expenses came in line with expectations for most categories in the third quarter. However, high natural gas price realizations and lower tax rate due to R&D tax credits taken in the quarter drove our earnings beat versus the Wall Street consensus. Putting it all together, operating cash flow totaled $1.7 billion in the third quarter with capital reinvestment rates at 52% of cash flow, generating $843 million of free cash flow and more than twofold increase versus the prior period. With this free cash flow, a key priority for us was to strengthen our financial position. In August, we paid off $242 million of maturing debt, and we bolstered liquidity with cash balances increasing by 56% to $761 million. With these actions, Devon exited the quarter with a net debt-to-EBITDA ratio of just over 0.5 turn. Moving forward, we plan to add to our financial strength in each quarter by committing around 30% of our free cash flow back to the balance sheet. This will allow us to further pare down our absolute debt balance with repayment of roughly $1 billion of maturities coming due in 2024 and 2025 and maintain a minimum cash balance in excess of $500 million. Cash returns to shareholders increased materially in the third quarter. Based on third quarter results, we declared a fixed plus variable dividend of $0.77 per share, an increase of 57% from the prior quarter. This dividend payout represents an attractive annualized yield of over 6% at today's share price. In addition to the dividend, we have a $3 billion share repurchase authorization in place. To-date, we've repurchased 400 million shares at a total cost of $2.1 billion. With this program, we are on pace to decrease Devon's outstanding share count by up to 9%. Although we temporarily paused our repurchase activity in the third quarter, retire debt and – excuse me, and to build cash, we continue to review buyback – or we continue to view buybacks as a critically important tool for us to compound per share growth for investors over time. As Rick stated earlier, we'll target 70% of free cash flow for cash returns to shareholders moving forward. With the recent weakness in our share price, investors should expect us to be an aggressive buyer of our equity once we come out of the earnings blackout and the general weighting of cash returns to be balanced towards share repurchases and our growing fixed dividend over the near term. With that, I'll turn the call back to Rick for some closing comments.

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.

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

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

Thank you. Good morning, everyone, and thanks for having me on. Rick, obviously, the issues in the Bakken and North Dakota are obviously well telegraphed at this point. Your commentary in the slide deck suggests that you’re taking steps to improve productivity. I wonder if you just walk us through what some of those steps are in terms of how the market can get confidence in the results. And at the same time, perhaps you could address your latest thoughts on inventory depth in that asset.

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?

Yes. And just for Mr. Coody, this is not a second question…

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

Yes, inventory in North Dakota.

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?

Yes. Doug, I’ll just add to that. I appreciate Rick’s comments. And one thing we’ve learned, we’ve been very open on the amount of surprise we’ve had specifically around some of the partially depleted wells that we’ve drilled. We’ve gotten operationally better. We’ve made three or four very specific changes that have improved how we develop those wells, how we bring them online, how we keep them online, small things like artificial lift and even the design of the completion itself. And so as we get better, that improves the productivity, ultimately the economics of those wells in the later life. And so those are learnings that eventually will apply to lots of other basins and feel real confident that given that same circumstance, we now have a better arsenal of tools to approach those wells.

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.

Yes. I appreciate it, Doug. Yes, we understand the bias that the market’s had for share repurchases, and that’s certainly going to be our bias going forward. But we – frankly, we always think the variable dividend can be a component of our framework and expect it to be as we move forward. I appreciate your comments on the balance sheet because again, I’ll just remind folks, as always, that’s our primary priority as we work our way into any year and any budget. We want to make sure we maintain the financial strength. And as you heard in my opening comments, we’re committed to continuing to reduce our absolute debt level. Beyond that, we’re going to grow the fixed dividend as we’ve talked about as well. We always take that up with our Board in the first quarter of the upcoming year. And as we highlighted it in our materials, we expect to grow the fixed dividend again next year. Beyond that, I think it’s – at least in our view, it’s pretty clear that the equity price is disconnected from the fundamentals of our business. And moving forward here in the near-term, we’re going to lean in on the share repurchases. And as Rick said in his comments, that could have an impact on the variable dividend going forward. But I don’t want to exclude it as an option for us because frankly we think it’s a key component of continuing to deliver cash returns to shareholders. But without doubt our bias is going to be towards the share repo here in the near-term.

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

Thank you, Doug.

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

Hey, good morning, guys, and thanks for taking my question.

Good morning.

Rick, it’s good to see the refocused energy around the Permian. I want to touch a little bit. You show about 3,000 potential locations in the Delaware in your deck. As you go back to the New Mexico Wolfcamp, the specific area that you’re targeting, can you talk a little bit about how much of that inventory is focused on that area alone?

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?

Well, as we think about kind of this 70-30 split, it does parallel our inventory. And so we think about most of our inventory being on that north side. Clearly, in 2023, we were very clear, we want to do a little bit more assessment work, spread some of that out. As I mentioned in my prepared remarks, we had to reach in a little bit deeper in some of the areas that we wouldn't normally have kind of reach into that bolt-in. That kind of diluted a little bit the average productivity that we delivered. I think working through that inventory – or, excuse me, working through that assessment work and really having a better understanding of where that sits. We're now leveraging those learnings into the activity in 2024 and then also allowing that infrastructure to mature a little bit also allows us to leverage back the benefits of the work we did in 2023 for the benefiting 2024. So there's a good parallel there, and I don't see us falling out of too much out of sync with that inventory run.

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?

Yes. And I think it's something that's very – obviously very topical in light of some of the recent transactions out there. Really, as you know, you've been covering this sector a long time, many people on the call are, but really it's part of the fabric of this industry, the sector. The one thing it won't change is our approach. And we've always had been very compelled, just have a high bar, be very disciplined and make sure that it fits within the framework that we have. And as you've heard Jeff talk about in my prepared remarks, I mean, right now, we see one of the greatest, most clear cut opportunities is just ourselves with our share repurchases. And so that's how we're looking at it. I do think that you'll continue to see consolidation. We've been on record as saying we support continued consolidation in the sector. We think it's the right thing to do for investors. But as far as Devon's participation, I'm going to go back to those key elements and we're going to have a high bar, be very disciplined, be very thoughtful, and make sure we can sell that to shareholders, that it's the right thing to do.

Thanks, Rick. Thanks for the answers.

You bet, Nitin.

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

Yes. Good morning, team. The question I had was – first question was just around the cadence of production, obviously, Q4 and Q1 a little softer and then a nice ramp over the course of the year. Can you talk about the confidence interval you have around that ramp as you get into – through 2024 and help the market get comfortable on the oil side in particular, as that's been a little bit shakier this year.

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.

Thank you. And then talk about the CapEx guide for 2024. It's a little bit lower than consensus, which is good, although partially offset by lower activity or lower production. So maybe just talk about what gets to the top end, what gets to the bottom end of the range and the modeling that went into building that 2024 forecast.

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.

Thanks, Team.

Thanks, Neil.

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

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, the good news is we’re in the hottest basin in the world. The bad news is when you’re in the hottest basin in the world you’re always going to have some kind of constraint. And so we work really closely with our third-parties on trying to stay ahead of that. In fact, we do proactive work on even modeling their own infrastructure. We’ve done some big projects this year. The Stateline processing facility that we are part of, we added a 200 million a day to that processing that not only benefits Stateline, but certainly some of the gas that we have in New Mexico as well. We worked very hard on some of the water infrastructure, made some great improvements on that, some redundancy there. So we feel really good about that really good work. Now we’re really focused on some of the electrification. While we’ve made good progress, I can tell you that’s going to be a continued focus for us and for industry. The weather specifically, around July, we had some serious windstorm blew over a lot of power lines. And as you can imagine, it’s not just getting those power lines back up, it’s not just getting our wells back up, but it’s all of the third-party infrastructure that’s daisy chained together. And so that’s where we saw some of the real tightness of that infrastructure, not having alternative outlets that you typically would in a looser environment. So that continues to build out. There’s been some really material improvement. But just know that this is a very active basin. Certainly Devon’s not the only company very active in the basin. And so we’ll continue to try our best to stay ahead, not just on our own controllable activity, but working with our third-parties so that they can stay ahead with us.

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?

Yes, I’m pulling the number now. It’s about 400, yes; it’s about 400 wells, relatively flat. It looks like we kind of peak a little bit more towards the middle two quarters, but relatively flat during the year.

Okay. I appreciate it. Thank you.

Thanks, sir.

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

Good morning, guys. My first question is just on the Permian infrastructure. I’m just wondering Rick and Clay have highlighted and I think been out there about the lack of infrastructure in recent quarters. I’m just wondering, was some that – did that come as surprise or was it you were thinking that some was going to be built out? I’m just wondering if you could speak to maybe what had changed and then maybe speak to the build out you’re seeing now and then what you anticipate next year.

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.

Yeah. Well said. And then my second question is just on your comment over high grading the upcoming multi-zone Wolfcamp wells in New Mexico. I’m just wondering, was it the infrastructure or what was the limitations to not high grade this Delaware sooner? And I’m just wondering what kind of runway do you all anticipate you’ll have in this core area?

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.

Thanks, Clay. Looking forward to the results.

Me too, Neil.

Our next question comes from Charles Meade from Johnson Rice. Charles, your line is now open. Please go ahead.

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?

Yes, Charles, it’s a bit of a whack-a-mole kind of opportunity. You bring on these big pads, and you’re really focused on gas takeaway or gas compression or processing. But as you bring these wells on, you’re also testing water. What we’re seeing is with everyone – the incredible electrical demand, some of the electricity providers are struggling to keep up with that growth. So we’re moving forward with some things to take a little bit more self-control on some of those projects and behind-the-meter opportunities to control our own destiny even a little bit more. But I can tell you as soon as we get one issue resolved, there’s other issues that pop up, and that’s just part of working in a very hot dynamic play. Now, what I will add to that, and I think is very important, we also see these as not just constraints, but opportunities. And we truly believe if we can identify them early, then we have options. We can wire around the issue. We can figure out how to work with third parties and develop and make sure that, that is built in time for our needs. We can certainly choose to drill alternate wells, reshuffle the portfolio or number four, we can lean in and be aggressive about capturing that value and leveraging that. And you’ve seen us do that a number of times. So I think the most important thing is being opportunistic, make sure we’re really thinking far out ahead and making sure we’re acting on that.

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.

Thank you for that elaboration Rick. And Clay I was going to say I came up – I consider using that term whack-a-mole, but I came up with the term cycling bottlenecks instead.

You’re reliant than I am.

A follow-up the question – feel free to use that one. A follow-up question perhaps for Jeff. Jeff, I think you clearly sent the message that you guys are tilting towards buybacks in the current circumstances that you see. But I wonder if you could elaborate a bit more on the framework that you guys have used to come to that conclusion. And with an eye with an eye towards if we do have the happy evolution where your stock price does go up at what point does it flip back towards the – more towards a variable dividend?

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.

Jeff, thanks for the detail.

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

Good morning, all. Maybe starting out a question for Clay. I was just curious if you could speak to some of the learnings from the down spacing tests and the Eagle Ford, maybe as it relates to the type curve performance on those titer space wells. And how many of your tills in 2023 were impacted by these tests versus kind of the high grading plan heading into 2024 that might improve that capital efficiency?

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.

Perfect. And then as a follow-up question, maybe for Rick or for Clay like the shift here and further improvement on the capital efficiency into 2024, I guess one of the questions that continues to come up, and Rick, you highlighted in your prepared remarks that we’re kind of in an uncertain time with spare capacity within OPEC and kind of the volatility in the crude markets as well as what might be a challenged 2024 gas market. Just curious, as you guys think through your capital allocation plans for 2024, where do things stand at the moment in the Powder River Basin and the Anadarko, just thinking through the return profile there versus areas like the Delaware and is there further optimization that could occur if we end up in a bit of a lower commodity price environment?

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.

Thank you.

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

Hey, good morning guys. And we appreciate all the details on 2024. You’ve talked about oil production taking a little bit before bouncing back up to what it looks like to maybe close to current levels at year-end 2024. And my question is, given that lumpiness, do you see the 2024 CapEx range is a good proxy for maintenance CapEx? And would that production level and the maintenance scenario would be kind of at the current production levels?

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.

Thanks. I think that clarity is helpful. And as a follow-up on the Eagle Ford, spending there has been a bit high this year. But in my take away from your CapEx budget is that it will be a little bit more efficient in 2024. Is that the right takeaway? And I respect you guys – that you guys are still nailing down the details, but anything you can share a high level on what's driving maybe better efficiency in the Eagle Ford?

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.

Thanks a lot.

Thank you, sir.

Our next question comes from Paul Cheng from Scotiabank. Paul, your line is now open.

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.

Hey Paul, this is Rick. I'm going to start, and then I'll put it over to Clay and Jeff, but I'm going to start with that second part. I think one of the most interesting things we've learned with the RimRock acquisition, some of which was a little bit of a surprise, some was not. And that was our spacing RimRock and Devon that had historically somewhat slightly different development schemes, if you will. And I think what we have learned is it really drove home the point that Devon's approach was probably the right approach as far as density per spacing unit. We were a little more relaxed. In other words, we had wider spacing and I think that's why we had better recoveries. But some of those – sometimes those points aren't really made until you have several years of production history, and I think that's what we have learned with this. The other thing I'd say is that we also have seen the impacts of something that's not controllable, like weather. And last year, not too much or make excuses, but the fact of the matter is we had one of the worst weather events in that area in the last century. And so timing was not our friend at that time, but you just have to, I think, think through that as you execute, implement your capital program. So I think those are the things we've learned as far as I can assure you the Williston has an absolute place in our portfolio going forward. It's an area we've worked in a long-time. We've had a great track record up there over the last decade, going back to the WPX days. And we see that continuing. We still see opportunities to even be better yet in the future. So we've learned quite a bit from this and we've applied that. I can tell you, I personally challenged the team to step up during that period; sometimes that happens when you're a leader, sometimes you push a little too hard. And I think that's a learning for us as well. So Clay, what else you want to add to those questions?

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.

Thank you.

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

Yes. Thanks. I think this one is for Jeff. And just to be a little bit more pointed on the kind of the buyback kind of theme. Your stock is down circa 30% year-to-date, certainly underperforming the peer group by quite a bit. Like why not do buybacks in the third quarter? I know you – obviously, the stock is bit down here in the last, say, week or so, but it had points during the third quarter to where it was at similar levels. Just kind of curious why not 3Q and more so going forward.

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.

Okay. Got it. And then my follow-up is, when you look at oil production next year around 315,000, do you see that as your new baseline? I know I think a prior kind of, I guess, market expectation would be closer to 320. And so is 315 the new baseline? And was – is that driven more about like where you think it's best sustainable at? Or is it more reflecting of your view of the uncertainty in the macro and just wanting to kind of taper it a little bit?

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.

Appreciate it. Thank you.

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.