Welcome to Devon Energy’s 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 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.

Thank you, Scott. It’s great to be here this morning, and we appreciate everyone taking the time to join us today. For Devon, the third quarter was another high-quality performance that demonstrated the flexibility of our strategy to create value in multiple ways. The team’s disciplined execution of our operating plan advanced earnings and cash flow by healthy double-digit rates on a year-over-year basis. Free cash flow was bolstered by capital efficiencies and effective supply chain management that drove capital spending below forecast. We rewarded shareholders with cash returns in the form of both dividends and buybacks that increased by nearly double over the past year. And we strengthened our asset portfolio by closing on two highly accretive bolt-on transactions that add to our ability to deliver sustainable long-term results, all in all, another great quarter of executing on our disciplined strategy. For my remaining comments today, I want to focus on the strategic moves we’ve taken recently to improve our business and the positive impact these actions have on our fourth quarter and our 2023 outlook. Turning to slide 4, we have worked hard through the years to assemble an asset portfolio that resides in the very best positioned plays on the U.S. cost curve. Being a low-cost producer with quality inventory is critical to our long-term success. And over the past few months, we’ve taken steps to opportunistically improve our asset portfolio. These bolt-on acquisitions were underpinned by exceptionally strong industrial logic that advanced both the financial and operational tenets of our strategic plan. First and foremost, from a financial perspective, the transactions represent a value-oriented consolidation of resources in the economic core of these respective basins, resulting in immediate financial accretion. The acquired assets were funded entirely from cash on hand and purchased at levels as low as 2 times cash flow and possess free cash flow yields ranging up to 30% at strip pricing. Furthermore, the addition of this incremental wedge of free cash flow also allows us to accelerate the return of cash to our shareholders through higher dividends and positions us to further compound per share growth through our ongoing stock buyback program. From an operational standpoint, these transactions fit like a glove within our existing asset portfolio and provide us improved economies of scale in the core of these respective plays. The direct adjacency of the acquired acreage also offers strong operational synergies and provides a meaningful runway of high-quality inventory that immediately competes for capital within our portfolio. Importantly, this resource capture allows us to sustain high-margin production from these assets for many years to come and does not require us to accelerate drilling activity across other parts of the portfolio to maintain our overall productive capacity. Altogether, I could not be more pleased with these tuck-in acquisitions as they successfully demonstrate another pathway that our business can create immediate value for shareholders. However, I do want to be clear that deals such as these that check every box are exceptionally rare. We will always look for smart ways to strengthen our portfolio, but you should be confident in our disciplined approach that focuses on quality assets, adjacency to our operations, and immediate per share accretion. On slide 5, in addition to enhancing our asset portfolio, we have also taken important steps to maximize realized pricing for our products. With our marketing strategy, we are focused on securing multiple low-cost transportation options in each basin we operate, with balanced exposure to domestic and international markets. By controlling firm capacity from the wellhead to the key demand centers, we’ve been able to steadily improve our price realization over the past few years. This progress is evidenced by the record oil realization we achieved in the third quarter that reached 101% of the WTI benchmark. A key contributor to the strong performance was the 20% equity interest in Penn Oak’s oil export terminal that we’ve accumulated over the past year. This investment in Penn Oak provides us 90,000 barrels per day of export capacity in Corpus Christi, offering valuable access to premium Brent-linked pricing that led to an uplift of more than $3 per barrel on these exports. We’ve also taken steps to secure additional pricing diversification for our natural gas portfolio by recently entering an LNG export partnership with Delfin Midstream. Once again, this arrangement will provide us with 150,000 MMBtu per day of direct exposure to international gas pricing, such as the lucrative TTF or JKM markets. However, I want to be clear, this is a capital-light approach to attain LNG exposure and our investment in Delfin, which is spread over this year and next, is very minor and will have a negligible impact on our capital outlook. A final investment decision for Delfin’s floating LNG vessel is expected to be made in the coming months, and we anticipate the facility will be operational within four years of this decision. Now turning to slide 7, with the positive tailwinds that come from our accretive bolt-on acquisitions, Devon’s upcoming fourth quarter is set to be a strong one. As you can see on the left, we are planning on delivering a high-single-digit growth rate in production per share. Capital will be higher in the fourth quarter, but our disciplined reinvestment rates remain at very low levels. Approximately two-thirds of the increased capital spending compared to the previous quarter is driven by our recent bolt-on acquisitions. The remaining third of the increase is a combination of higher service costs as contracts refresh, a bit more operated activity than previously planned helps our operational flexibility as we head into 2023. We have seen an uptick in non-operated activity. Overall, it will be another great quarter for us as we expect to deliver free cash flow growth of more than 25% on a year-over-year basis. At today’s pricing, this outlook translates into a compelling free cash flow yield of 11% or nearly three times what the S&P 500 index offers investors. With this excess cash flow, there is no change to our cash return playbook, it will be more of the same. As you can see on slides 9 and 10, we will continue to accelerate the return of capital to shareholders through our market-leading dividend, which is one of the top yielding equities in the S&P 500, and we remain active buyers of our stock when the market presents us opportunities. This operational and financial momentum will also carry into 2023. I will hold off on detailed line item guidance today since we’re still integrating the recent acquisitions of RimRock and Validus into our capital allocation process. However, I can confidently say that our Delaware asset will continue to be the focal point of our capital program, and we’re focused on designing a plan with consistent activity levels that delivers the right balance between returns, capital efficiencies, and free cash flow. With the benefit of acquisitions, we do expect to grow production in 2023. However, compared to fourth quarter exit rates, our volumes in the upcoming year are likely to be in the bottom half of our targeted growth range of 0% to 5%. The capital activity levels required to sustain production at these levels will be similar to the program we’re deploying in the fourth quarter of this year. Although we could pull back on less efficient rigs when considering the incremental activity we’ve recently added in the Delaware, we still expect to experience some additional upward pressure on costs as contracts refresh, especially in the second half of the year. Price discovery is still ongoing and very sensitive to industry activity levels and commodity pricing. We will provide official guidance in February, but I’m confident that 2023 is going to be another great year for Devon as we are well positioned to generate substantial free cash flow and execute on all facets of our cash return model. With that, I will now turn the call over to Clay to cover our operational highlights.

Thank you, Rick, and good morning, everyone. Devon’s consistent quarterly performance exemplifies the importance of balancing three things: first, the value of well-communicated, consistent, and long-term business strategy; second, a 24-plus month planning process that details out the development schedule, supply chain, the takeaway needs, and any potential pinch points; and third, and critically important, near-term execution, also known as getting it done. Although the third quarter was another quarter, our team was working hard to deliver on all phases. Altogether, we were able to deliver on our business, continue to strengthen and build momentum. During the quarter, the team delivered results that exceeded expectations by focusing on capital efficiency and strong well productivity. In addition to the important blocking and tackling associated with our day-to-day operations, we also invested substantial amounts of effort to ensure that we integrate the recent acquisitions into the business the right way so that we can maximize the value of these assets for shareholders. The integration is not just simply teaching the new people how we do it at Devon, but taking the time to learn, challenge, and improve our own processes. On slide 14, let’s begin with an overview of our Delaware Basin operations, which account for more than 60% of our total activity and drove the overall company performance in the quarter. To optimize the returns of our capital program in this tight market, we’ve been very thoughtful in designing a plan with steady activity levels that has resulted in an average of 14 rigs and 3 frac crews year-to-date. On the top right chart, you can see that this disciplined capital allocation in the Delaware is working well, resulting in a healthy production growth rate of 11% year-to-date. Importantly, the low-risk development projects underpinning this volume growth have delivered world-class returns with IRRs consistent in the triple digits. Another win for us can be seen in the bottom left, where the team has leveraged our substantial operating scale to maximize the value of our production. With good upfront planning and economies of scale in the basin, we’ve been able to effectively control operating costs even as commodity prices have gravitated much higher over the last few years. On the bottom right, this cost mitigation strategy has allowed us to materially benefit from the higher prices, with margins expanding by 260% over the past few years. Looking specifically at the quarter’s results on slide 15, the Delaware team continued to do a great job of achieving operating efficiencies. On the chart to the right, new well activity was highlighted by several high-impact development pads, but the most prolific result was achieved by the CDU 604H in Southern Eddy County. This 3-mile lateral was our first test of the Wolfcamp B interval in the Cotton Draw area, delivering a 30-day rate of just over 6,500 BOE per day, with estimated recoveries for this well trending towards 3 million BOE. It’s not bad for a secondary target. In addition to our outstanding well productivity, we have not seen any meaningful communication with the shallower zones in the Wolfcamp such as the Wolfcamp A or XY sands, which deepens our quality of inventory and provides us flexibility to optimize future development plans in this portion of the field. As I mentioned in my earlier comments, the strategic development of these target-rich assets is some of the most complicated and important work we do. Results like this give us confidence that we’re getting things right. We also made great progress advancing drilling and completion efficiencies across our operations in the basin. In the Wolfcamp, we improved drilling productivity by 13% on a per-foot basis versus last quarter, with some of our best spud rig release times for 2-mile wells, pushing below 20 days. Completion efficiencies have also steadily progressed, as were highlighted by a record-setting performance on a Cotton Draw pad, where our completion pace reached an average of 3,200 feet per day. While we have made a lot of progress on efficiencies over the last few years, these D&C results showcase the incremental improvements the team is making every day to reduce cycle times, refine completion designs, and deploy leading-edge technology across all facets of the value chain. Moving to slide 16, I’m also excited about the positive results we’re seeing delivered and the other key assets across our portfolio. In the Anadarko Basin with our 4-rig program, the team’s approach of wider spacing and larger completion designs is delivering excellent results. A great example of this resource progression was the auto development in the condensate window of Canadian County. This 5-well project, which co-developed the Meramec and Woodford formations, attained an average 30-day rate of more than 2,700 BOE per day. The strong well productivity we are experiencing, coupled with our $100 million Dow drilling carry, positions this liquid-rich gas play to compete for capital with any asset in our portfolio. Moving to the Williston. This asset continues its tradition of delivering some of the best returns and highest oil rates in our portfolio, with another batch of great wells brought online during the quarter. Coupled with the RimRock acquisition, oil production advanced 30% versus last quarter. The team is also making substantial progress integrating the RimRock acquisition into our operations. Because of this transaction, we expect volumes to take another step up to around 65,000 BOE per day by year-end. This enhanced production profile now puts our Williston asset on pace to generate around $1 billion of cash flow for this year. Turning to the Powder River Basin. We’re encouraged by the results from our Niobrara appraisal activity in the quarter. The top highlight was a 3-mile lateral SSU MLT project in Converse County that helped further validate the commerciality of the spacing test. With improved completion design that pumped 3,000 pounds of sand per foot, all SSU MLT wells performed above type curve expectations with 30-day rates averaging 1,400 BOE per day, of which 86% was oil. Importantly, we’re still experiencing strong reservoir pressure and shallower declines than forecasted, with per well recoveries on track to reach 1.2 million barrels of oil equivalent. While we still have a lot of work ahead of us, this positive result adds to the conviction that the Niobrara will be a repeatable resource play and an important growth driver for Devon in the future. Lastly, in the Eagle Ford, the results from the infill and redevelopment activity across our legacy position in DeWitt County continue to demonstrate that there’s a lot more oil to be recovered from this prolific play over time. During the quarter, we brought on 8 new infill wells bounded by existing producers that delivered 30-day rates averaging 3,200 BOE per day. Slide 17 provides a more detailed overview of our recent Validus acquisition. This opportunistic acquisition doubles the scale of our position in the Eagle Ford and captures a repeatable resource play in the best part of the Karnes Trough oil window. As you can see on the map, the transaction secures an operated position of 42,000 net acres with a high working interest of 90% that’s adjacent to our existing footprint in the play. The oil-weighted production mix of around 35,000 BOE per day provides strong cash operating margins through access to the premium Gulf Coast pricing, low per-unit operating and GP&T cost of around $6 per BOE. With enhanced scale in the basin, we expect to realize $50 million in average annual cash flow savings from the capital efficiencies, operating improvements, and marketing synergies. Furthermore, the core of the Eagle Ford is proving to be one of the best opportunities in the world for downspacing, redevelopment, refracs, and also EOR. We have identified roughly 500 economic opportunities across the Validus acreage, and this inventory allows us to sustain the high-margin production from our Eagle Ford assets for years to come. And lastly, on slide 18. With our recent resource capture, I wanted to end my comments today by covering the depth and quality of our inventory, which we believe is differentiating compared to the vast majority of the E&Ps out there. Turning your attention to the middle bar on the chart. At our current pace of activity, we’ve identified 12 years of high-return development inventory, delivering greater than a 30% return with $65 WTI and 3.25 Henry Hub pricing. This inventory disclosure reflects the confidence we have in delivering repeatable, capital-efficient results for many years to come. As you would expect, the majority of our risked inventory resides in the target-rich Delaware Basin, but we’re also stocked with healthy amounts of high-return inventory across all of our key assets. To be clear, this rigorous characterization is a result of existing well control and detailed subsurface work, but it is not meant to convey the full extent of our resource base. This bar only represents the high-confidence operated inventory that delivers competitive return in a conservative mid-cycle price scenario. Moving to the bar on the right, with a higher commodity price and further derisking of our portfolio over time, we estimate that our inventory extends more than 20 years at the current activity base. This upside scenario assumes that we capture additional efficiencies, fine-tune spacing at higher prices, and further delineate the geologically rich columns across our acreage footprint. However, I will be quick to add that the upside we’ve identified is not an exercise including every molecule potential. We fully expect a significant portion of the upside opportunities to come into development over time. Tangible examples of these upside opportunities that the team is currently progressing include massive amounts of resource potential residing in the deeper Wolfcamp intervals, tighter redevelopment spacing and refracs success in the Eagle Ford, ongoing appraisal work in the Powder River Basin to further derisk the Niobrara, and improving capital efficiency that is unlocking resource potential in the Anadarko. The bottom line here is that we have an abundance of highly economic opportunities that will continue to deliver top-tier capital efficiency for the foreseeable future. And with that, I’ll turn over the call to Jeff for a financial review.

Thanks, Clay. I’d like to spend my time today discussing the highlights of our financial performance for the quarter and the capital allocation priorities for our free cash flow. A good place to start is on slide 6 with a review of Devon’s financial performance, where earnings and cash flow per share growth rapidly expanded year-over-year and exceeded consensus expectations. Operating cash flow for the third quarter totaled $2.1 billion, an impressive increase of 32% compared to the third quarter of last year. This level of cash flow generation comfortably funded our capital spending requirements and resulted in $1.5 billion of free cash flow in the quarter. As you can see on the chart to the right, this strong result keeps us on track to generate a record-setting amount of free cash flow this year and is a powerful example of the financial results our disciplined cash return business model can deliver. With the free cash flow Devon generated this quarter, our top priority is to reward shareholders with higher cash returns through our fixed plus variable dividend framework. This dividend strategy is foundational to our capital allocation process, providing us the flexibility to return cash to shareholders across a variety of market conditions. Under this framework, we pay a fixed dividend every quarter and evaluate a variable distribution of up to 50% of the remaining free cash flow. Based on our strong third quarter financial results, the Board approved a 61% increase in our dividend payout per year-over-year to $1.35 per share. On slide 9, you can see that our large dividend translates into a very compelling yield compared to other segments of the broader market. In fact, at today’s pricing, our yield is substantially higher than the average company in the S&P 500 index. Another priority for our free cash flow is the execution of our ongoing $2 billion share repurchase program. On slide 10, you can see that over the past year, we bought back $1.3 billion of stock, which has reduced our outstanding share count by 4%. This equates to an average price of $50 per share, which is more than a 30% discount to our current trading levels. Over the past several months, our buyback activity has been somewhat limited due to our recent bolt-on acquisitions in the Williston and Eagle Ford. However, with those transactions now closed and with around $700 million remaining on our authorization, we can be more active buyers of our stock when the market opportunities present themselves. To round out my prepared remarks this morning, I’d like to give a brief update on our investment-grade financial position. After funding $2.5 billion of acquisitions from cash on hand during the quarter, we exited September with a healthy cash balance of $1.3 billion and low leverage with a net debt-to-EBITDA ratio of around 0.5 a turn. Even with this strong financial position, we’re not done making improvements, and we’ll continue to evaluate opportunities within our debt stack to create additional value for shareholders. With that, I’ll turn the call back to Rick for some closing comments.

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 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 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.

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

Our first question comes from Arun Jayaram with JP Morgan.

Yes. Good morning. Rick, I wanted to start, you provided some, call it, soft guidance commentary for 2023. I respect the fact that you’re still in your capital budgeting process. But let’s go back to your prepared comments. You mentioned that you expected targeted growth to be at the low end of the 0% to 5% range from the 4Q exit rate. When we think about the 4Q exit rate, is that basically the 4Q guide of 650,000 BOE per day at the midpoint and 322.5 for oil? Just trying to get your definition of the exit rate?

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.

Great. Okay. My second question for you, Rick, is to get your thoughts on what you think is the appropriate development scheme for shale in above mid-cycle conditions. We get a lot of questions from this from the buy side. But one of your peers has decided to high-grade their 2023 program to develop, call it, higher return locations starting next year. In the broader context of the fact that shale inventories are finite in nature, do you think it makes sense for Devon today to tailor your development programs on maximizing IRRs or NPV per section? I’d love to get your thoughts on that idea.

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?

Yes. Rick, I think you nailed it with balancing IRR and NPV as an important consideration. And of course, you have all the practical realities of we got to make sure we have takeaway. We want to make sure we’re doing the right thing from an ESG perspective. We’re thinking about assessing future potential. Those always don’t necessarily command the highest risk rate of return today, but it’s incredibly important as we think about not just this quarter’s return or year’s return, but three-year, five-year, ten-year returns as well.

Our next question comes from Neil Mehta with Goldman Sachs.

Yes. Good morning, team. Rick, I wanted to get your perspective on these opportunistic bolt-ons. We’ve had Validus Energy and RimRock and as you said, you acquired them at very attractive multiples. What is the opportunity set that you see around similar type of acquisitions? And can this become a core part of your go-forward business model rolling up assets and arbitraging the multiple?

That's a great question, Neil. From our standpoint, we've been consistent in saying that we will always look for transactions that can enhance our company. Our goal is to ensure we deliver value over time, which will be reflected in our income statement. As you mentioned, if we can deepen our inventory, that's crucial. We'll keep pursuing consolidation as a key part of our strategy. However, as I noted in our prepared remarks, we don't always find deals that meet all our criteria, and we won't overpay. We're committed to being disciplined. The two recent transactions fit our needs well, and there may be more opportunities in the future, but we're going to be patient. We're proud of our accomplishments, and I want to acknowledge the team that successfully completed these deals; they truly benefit us in many ways.

And the follow-up is just on capital spending. It’s been the focus of investor conversations this morning. You talked a little bit about it in the prepared remarks, but can you once again bridge between old and new guidance for 2022 spend? And just how we should think about how much of this bleeds into the way we should think about ‘23 as well? Thank you.

Yes. I think I’m going to ask Clay to go into maybe some of the details. 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. 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.

Yes, Rick. First of all, there is inflation present. We have not been ignoring inflation; it is a reality. As we renew contracts, we notice it continuing to increase. I believe we are starting to see a peak in that trend, with perhaps some signs of improvement and easing in certain areas. We will keep an eye on this situation. It is too soon to determine how this will play out throughout 2023. That addresses the first point. Secondly, we took the opportunity to increase our activity a bit to get a head start on 2023. You will notice this particularly in the new wells that were started in November and December, which will see a slight rise in the spud count. Additionally, as we look at our partners, non-operational activities have also increased. When breaking this down, two-thirds of the increase comes from acquisition activity, with the remaining portion roughly divided into thirds. We feel optimistic about our position and outlook for 2023.

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

Guys, I wonder if I could go to Clay first and then to Jeff. Thanks. Clay, your comments about testing wider spacing, I guess, in the Mid-Con. I’m looking at slide 18. And to get from the 12-year inventory to the 20-year inventory, one of the comments under there is appraisal and tighter spacing. So I wonder if you can reconcile what does upspacing mean for your confidence in that increased longer-term inventory guidance.

Yes, Doug, I appreciate the chance to explain that. The upspacing is really compared to what we experienced during the difficult years in the STACK when the industry was too aggressive with well spacing, overlooking well-to-well interference and isolation, and essentially over-drilling. Currently, we are observing outstanding returns. However, as you know, we need to adapt continuously to changing factors such as commodity prices, drilling costs, and realizations. We are assessing whether 3, 4, or 5 is the appropriate spacing specifically for the Mid-Con region. But broadly, as we examine the entire basin and shift from a midpoint of a $65 price assumption to an $85 price in our larger projections, we also have to reevaluate how that might apply in different areas. The Powder River still needs clarity on the spacing strategy, and there’s considerable potential in the deeper sections of the Delaware Basin, which is highly influenced by the commodity prices we apply. Additionally, in the Mid-Con area, there is substantial opportunity with gas, which is crucial as we formulate our price strategy, examine our realizations, and ultimately determine the best economic method to maximize value extraction.

Sorry. Clay, just to be clear, did you say $85 oil for the 10,000 locations?

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

Yes, it’s in that neighborhood, Doug. For the unrisked, we did have a higher price point that reflects current spot pricing, considering the ongoing regulatory unrest. Additionally, we reduced some of the risks associated with the appraisal that needs to succeed for that column to transition into our risked category over time.

My follow-up is a quick question for Jeff regarding Rick's comment about free cash flow in the fourth quarter over 2021. Jeff, it appears that there is about an 80% deferred cash tax included in the $1.5 billion free cash flow number for the third quarter. When can we expect to see a more normalized cash tax in the future? Thank you.

Yes, Doug, thank you for your question. In the third quarter, we adjusted our expectation for the full-year cash tax level. We had been estimating around a 10% cash tax burden, but now we believe it will be closer to 8%. The main reason for this change is that we are benefiting from certain tax attributes, primarily NOLs. Looking ahead to next year, we will carry forward about $1 billion of NOLs that we can utilize over several years. This will help keep our tax liabilities manageable as we progress. However, as we have discussed previously, if we assume current commodity price levels and cost structures, we expect to see our current tax level around 15% as we move through next year.

Our next question comes from Jeanine Wai with Barclays.

My first question is for Clay. Regarding inventory, we appreciate all the details on slide 18. Can you provide more information about the Delaware? It appears that out of the over 4,500 risked locations, about 55% are in the Delaware. Our question is about the mix of zones within that estimate. Specifically, how many of those 55% of locations would you classify as Tier 1, particularly in Wolfcamp A, XY?

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.

Okay. Great. And then, maybe sticking on ops here on base declines. So in Q2, the Delaware total in oil production, it grew significantly. I think it was like 22% year-over-year in Q2 and 16% on oil. In Q3, the year-over-year growth, it slowed, and oil, I think, was down like 3,000 a day versus Q3 of last year. So just maybe smashing everything together, we’ve got flattish oil expected in Q4 in the Delaware. Can you provide an update on what you think the oil-based decline will be for the Delaware going forward? And then maybe for the overall company as you put in the Bakken and Eagle Ford deals?

Thank you, Jeanine. You're correct in noting that when we compare quarters, there can be significant fluctuations from last year to this year. It's important to consider year-over-year trends. We expect to maintain healthy growth; we've reported an 11% increase year-to-date. Regarding the base decline, it's approximately 30% to 35%, leaning closer to 30%. As we temper our growth, these figures will decrease, which is advantageous for our business model. We anticipate continued mitigation over time, allowing us to keep production steady and more capital-efficient. Yes. Coincidentally, really both. But yes, for both.

Our next question comes from Paul Cheng with Scotiabank.

I have two questions. The first is for Jeff and the second is for Clay. Jeff, in your presentation, you mentioned that management efforts and streamlining have resulted in a higher unit depreciation, depletion, and amortization. Can you explain the extent of what you're doing that leads to this higher unit DD&A? What benefits do you expect from these efforts? Secondly, regarding the recent acquisition in Eagle Ford, will this impact how you view your joint venture with BP in the area? Will it change the focus or attention for the companies involved? Is there any way this will have an impact?

Hey Paul, this is Jeff. Yes, happy to address your question on DD&A. It’s a little bit of the nuance of successful efforts accounting, and you’re probably aware, we have different common operating fields or cost centers, if you will, kind of across the company as to align with how we kind of manage the operations. Post the merger that we did with WPX, we actually kept our Delaware South and North assets separate. So, New Mexico to the north, obviously and Texas to the South. Here, over the last couple of quarters, we decided to consolidate that all into one cost center. As a result, you have spread that cost of those units across the entirety of that new business unit or cost center, if you will. As a result, you have a slight increase in the DD&A rate going forward to the overall company as a result of kind of streamlining that effort driven by the consolidation of those two cost centers.

Paul, this is Clay. I’ll pick up on the second question. So, our joint venture with BP is really a separate discussion. Now clearly, as we scale up our activities, we will bring our learnings, that economy of scale to BP as the drilling and completions operator and then vice versa. We’re also bringing knowledge to the Validus assets. Also, remember, as part of the JV, Devon operates the joint venture wells. So there’s definitely economies of scale in our operations, some of the technologies that we use, some of the efficiencies around the people, being able to cover essentially more with less. That’s always very good as you scale up these opportunities. I think one of my favorite tests to do is as you look at one of these deals is just glance at the map. If it makes sense from an industrial logic standpoint, you know there is some real efficiencies to be gained, and we’re certainly going after those right now.

Our next question comes from Scott Gruber with Citigroup.

So on the Validus acquisition in the Eagle Ford, you identified about 500 locations, which looks to double your total in the basin, as I squinted that inventory STACK bar chart. Are all these new drill locations, or do these figures include refrac opportunities? And if refrac is not included, how good could the refrac opportunity be?

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 economically and be able to restimulate and really stimulate new rock is the key to success there.

And as you study the opportunity set, how would you describe the economics of refrac today? And how would you think about layering them in over the next couple of years?

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. 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? 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.

Our next question comes from Neal Dingmann with Truist.

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?

Yes. You bet. Neal, this is Jeff. We feel really good, frankly, about our ability to move the molecules. You’ve heard us talk about this in the past, and we’ve had these dislocations in pricing in Waha over the last couple of years, and the team has done a great job of kind of protecting us from that exposure. As a big picture, we move, call it, north of 50%, almost 60% of our volumes are gas molecules out of the basin to the Gulf Coast. Those volumes actually have exposure to Houston Ship Channel pricing. With the remainder of the molecules that sit in basin, we’ve hedged almost all of that. So, the remainder of volumes that are specifically exposed to Waha is about 10% of our gas molecules in basin. So, when you put that all together, just to give you some context, less than 1% of our revenues as a total company are exposed to Waha at this point given the lengths that we’ve gone to, number one, move the molecules out of basin and then number two, hedge our exposure there.

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?

Yes, you bet. No, we’re excited about the opportunity with Delfin. We’re a little light on details at this point because we’re still in the process of negotiating some of the commercial terms there and how all that shakes out. But generally speaking, it’s really just an extension of our broader marketing philosophy and thought process, which is we’re always trying to capture the highest realized price wherever we can for our molecules while at the same time, balancing our exposure to the different markets that we’re involved in. As we look forward over the next 5 and 10 years, we really expect the growth in demand for natural gas to come outside of the United States. For us, it makes sense to have exposure to the water and those international markets. So, we’re excited that we could take a step forward with Delfin, make a relatively minor investment with them, which is going to provide us some access to those international markets going forward. I’ll remind everybody that those projects, we don’t expect to come on line until the kind of the 2026 timeframe, but we’re excited to kind of work things forward with that group and then hopefully get us exposure to the premium markets that we’re seeing internationally.

Our next question comes from John Freeman with Raymond James.

Thank you. Yes. My first question is a little bit of a follow-up to what Jeanine and Doug were talking to you on slide 18. I guess just when I think about the risked inventory that you’ve got at the moment and we think about sort of the balancing act of adding to that risked inventory, either via bolt-on deals like you have done recently versus appraisal and testing to kind of move that upside location count into the risked inventory. I guess when you just sort of look out the next 2, 3 years, I mean, would you anticipate that more of those risk inventory locations comes from more of these kind of bolt-on deals, or is it more from kind of the appraisal, testing, spacing type of efforts?

Thanks for the question, John. This is Clay again. Regarding the appraisal, we are considering the work we’re doing in various horizons that are not fully defined regarding downspacing and the optimal spacing tests. We are also looking at whether there are two or three landing zones in some of these intervals. Moreover, when I think about areas further out, like the Powder, there are more opportunities to add to that number from the appraisal perspective. To clarify, we do not have any assumptions regarding future acquisitions or additional integrations in any of these figures.

And then, when I think about for next year, I appreciate some of the early kind of color on how to think about 2023 from an activity standpoint and some of the cost inflation levers. Is there anything from like a midstream perspective on a year-over-year basis that we should also consider whether it’s related to some of the bolt-ons recently getting bigger in some of these areas, just that necessitate some more midstream infrastructure spending in ‘23 versus ‘22 and we’ll kind of trying to finalize what we think about the ‘23 budget?

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

Our next question comes from Matthew Portillo with TPH.

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 all 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 regarding timing during the fourth quarter that might have led to some of the guidance shaking out in Q4.

Yes, thank you, Matt. I appreciate the opportunity to discuss this because the well performance is exceptional. This is truly a top-tier asset. We are very pleased with our position and the scale we have. The team continues to deliver results. We are still focused on improving efficiencies and consistently applying technology, always striving to get a bit better and smarter every day. There is some inflation on the horizon, which may impact our margins, but I would much rather have this outstanding asset in our portfolio. I'm extremely satisfied with the team’s efforts and what they are achieving.

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?

Thanks for the question on STACK, Matt. Again, the team is looking at this holistically, thinking about what’s the right way to extract the optimum value, balancing rate of return and balancing NPV, and thinking about the levers that we have. The first and the most significant is well spacing. The second, of course, is completion design. Both of those I mentioned in my prepared remarks. We like the approach that we have. Clearly, we have to understand what commodity prices will do. As those numbers rise up on gas and NGL realizations, there’s an opportunity for us to maybe even take a step tighter and still achieve super competitive returns. So, we’re still working on that. Like what we’re seeing as we move into the gas window, certainly the higher commodity price and gas certainly helps. It’s a significant amount of upside for our inventory. As we think about the midstream, the nice thing about working in the Anadarko Basin is a lot of built-out midstream. So, we feel really good about the runway. Of course, we have regular conversations with our midstream partners trying to stay out years ahead because these big wells, especially with the gas volumes, can take up a lot of space in pipe and in plants. We want to make sure we’re telegraphing what we’re doing to our midstream partners. I would say those conversations are going along very, very well.

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

Good morning, guys. And congratulations on a good production quarter above guidance. The only area you didn’t beat our expectations was in the Bakken. I wonder if you could talk about the integration of the RimRock assets and what you expect the trajectory of the production to be? You mentioned earlier that there was a 65,000 barrel a day exit rate. Is that for the full quarter, or will you expect to grow above that next year?

Yes. I would say that the 65,000 BOE per day is approximately what it would be for the quarter. I appreciate the recognition of the third quarter; it can sometimes be overlooked. The teams have worked exceptionally hard to maintain performance, and we are very pleased with that. As we take over any acquisition deals in the Williston, there will undoubtedly be handoffs and minor challenges. There was a specific pad that had some delays. Running on a smaller scale means that just a few days or a week of delay can lead to larger setbacks when trying to manage equipment. That affected us there. We faced a bit of a transition issue, but I believe we have the team up and running now. I feel really good about that. I have often praised the Williston team in earnings calls; I hold them in high regard and trust their execution. Integration is not typically our core competency, but we have taken it upon ourselves to excel in this area. I am really proud of the results we are seeing throughout the organization, from HR to IT to accounting, with everyone collaborating to effectively bring these assets in and ultimately maximize value for the shareholders.

Well, I appreciate everyone’s interest in Devon today. 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. Thank you.

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