Welcome to Pioneer Natural Resources' third quarter conference call. Joining us today will be Scott Sheffield, Chief Executive Officer, Rich Dealy, President and Chief Operating Officer, and Neal Shah, Senior Vice President and Chief Financial Officer. Pioneer has prepared presentation slides to supplement comments made today. These slides are available on the internet at www.pxd.com. Again, the internet website to access slides presented in today's call is www.pxd.com. Navigate to the Investors tab found at the top of the webpage and then select Investor Presentations. Today's call is being recorded. A replay of the call will be archived on www.pxd.com through November 22, 2022. The company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from forward-looking statements. These risks and uncertainties are described in Pioneer's news release on page two of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission. At this time, for opening remarks, I would like to turn the call over to Pioneer's Senior Vice President and Chief Financial Officer, Neal Shah. Please go ahead, sir. Thank you, Melinda. Good morning, everyone, and thank you for joining us for Pioneer's third quarter earnings call. Today, we will highlight Pioneer's excellent third quarter financial and operating results and peer-leading return of capital strategy. Importantly, we will discuss the increased return thresholds we are instituting beginning with our 2023 program, as well as the strong benefit we are seeing through our long lateral development. We're also excited to highlight our participation in two renewable energy projects that will help reduce our emissions profile and further strengthen our leading ESG strategy. We will then open up the call for questions. With that, I will turn it over to Scott. Thank you, Neal. Good morning. Starting on slide three, Pioneer delivered strong results, generating over $1.7 billion in free cash flow during the third quarter, contributing to the return of $1.9 billion back to the shareholders. The majority of this capital is being returned through our base plus variable dividend of $5.71 per share, which will be paid in mid-December. Additionally, we continue to execute on opportunistic share repurchases, with $500 million in shares retired during the third quarter at an average price of $218, representing approximately 2.3 million shares. This strong return of capital through both dividends and share repurchases represents approximately 108% of our third quarter free cash flow. When including all repurchased to date and dividends to be paid in 2022, we will return approximately $7.5 billion to shareholders this year. This robust return clearly demonstrates our commitment to our investment framework that is supported by our significant free cash flow generation. We are also pleased to announce that we're participating in a 140-MW wind generation project with NextEra. This project utilizes Pioneer's own service acreage to generate renewable energy that we will utilize in our operation. Going to slide four on our third quarter results. Pioneer's strong execution continued during the third quarter with both oil and total production in the upper half of our guidance range, driving substantial free cash flow generation of greater than $1.7 billion. Our leverage profile remains top tier, which we forecast to be less than 0.3 net debt to EBITDA at year-end. Going to slide five. Supplementing our best-in-class dividend payout, we continue to repurchase our shares opportunistically and have executed $1.5 billion since the fourth quarter of 2021 at an average share price of $219. This represents a reduction of total shares outstanding by approximately 3% at a strong discount to our current share price. Of the $500 million repurchased during the third quarter at an average price of $218 per share, $250 million of stock was repurchased in the month of July at an average share price of $213 through our 10b5-1 program. To date, we've utilized $1.25 billion of our current $4 billion authorization, leaving nearly $3 billion remaining under the program. Going to slide number six. Our core investment thesis remains unchanged, underpinned by low leverage, strong corporate returns, and a low reinvestment rate. This delivers moderate oil production growth, which generates significant free cash flow. Majority of this free cash flow was returned to shareholders through our strong and growing base dividend and our peer-leading variable dividend, which represents up to 75% of post-base dividend free cash flow. We strengthened this quarter's total return by leveraging our strong balance sheet to aggressively repurchase shares. In total, this resulted in returning $1.9 billion to shareholders, which equates to an annualized yield of greater than 12%. Going to slide number seven. Pioneer's high-quality assets, low breakeven, and moderate oil growth provides the ability to pay significant dividends from our peer-leading free cash flow through cycle. As seen on the graph, we're able to deliver a compelling base plus variable dividend, with a yield far exceeding the S&P average at oil prices of $60. Conversely, shareholders have significant upside to sustain higher oil prices as well. With a greater than a 10% dividend yield at all prices higher than $100 WTI. Going to slide number eight. Total dividends to be paid in 2022 result in a yield in excess of 10% at today's share price. This yield exceeds all peers, majors, and the average yield of the S&P 500. Going to slide number nine. When looking beyond our peer group to the broader market, Pioneer's dividend yield exceeds every S&P 500 sector. Our double-digit dividend yield demonstrates the cash flow generative power and underlying quality of Pioneer's assets and the strength of our peer-leading return of capital strategy. I'll now turn it over to Rich. Thanks, Scott, and good morning, everybody. I'm gonna start on slide 10, where you can see that our full year 2022 production and capital guidance remains unchanged from our previous update in August. Updating for actual results for the third quarter and forecasted strip prices for the fourth quarter, we are now estimating that we'll generate over $12 billion in operating cash flow for the year, excuse me, and deliver more than $8 billion of free cash flow for the year. As you can see in the upper right, our average activity level remains unchanged, and we plan to run between 22 and 24 rigs and approximately six frack fleets, with two of those being simul-frac fleets for the remainder of the year. Turning to slide 11. As you would expect, we continually strive to be more efficient, improve return, and implement the learnings into our development program. Consistent with this DNA inside the company, we have been not satisfied with the 2022 well performance and have made a significant step change to our well return thresholds going forward. This material threshold increase will substantially improve well productivity for 2023 and subsequent years. Implementing these more stringent thresholds will result in the productivity of our future development programs surpassing the 2021 program levels, which are significantly higher than the 2022 levels, and result in better capital efficiency and higher free cash flow per BOE. Over the course of 2022, our development strategy has fully transitioned to a full-stack approach, which includes drilling up to six highly productive zones. We have also significantly reduced our delayed developments and are taking advantage of our contiguous acreage position to drill extended 15,000-ft laterals that generate 20% higher returns than a 10,000-ft well. Given the quality and depth of our inventory, this higher threshold program is consistent and highly repeatable for many years past the 2023-2027 period highlighted on the graph in the right. Turning to slide 12, and as I mentioned on the previous slide, we are realizing improved returns and strong productivity from drilling 15,000-ft lateral wells. Developing these long laterals provides significant efficiency gains that reduce capital costs, resulting in an average drilling and completion savings of approximately 15% per lateral foot. The combination of these savings and the strong productivity drive increased returns, with IRRs increasing by more than 20 percentage points when compared to 10,000-ft laterals. Pioneer's extensive contiguous acreage position in the Midland Basin, which approaches nearly 1 million gross acres, supports our development of high-return 15,000-ft lateral wells. To date, we have identified more than 1,000 locations for long lateral development and expect to place more than 100 of those wells online in 2023, up from the 50 or so that we plan to put online in 2022. Turning to slide 13. As you can see on the left, Pioneer has the longest duration of high-quality inventory when compared to peers. This third-party data highlights Pioneer as a premier independent oil and gas company with decades of high-quality inventory in the core of the Midland Basin. Turning to slide 14. This slide highlights the powerful combination of Pioneer's highest free cash flow per BOE amongst our peers, combined with having the longest duration of high quality of inventory in the U.S. unconventional space. This combination of robust free cash flow generation and decades of high-return inventory supports Pioneer's ability to return significant capital to shareholders over a long period of time and differentiates Pioneer from its peers. I'll stop there and turn it over to Neal. Thank you, Rich. Turning to slide 15. For multiple consecutive quarters, Pioneer has delivered the highest cash margin of our entire peer group. Our unhedged oil-weighted production underpins strong price realizations, which, when netted against our low cash costs, drive these unmatched results. As we've discussed previously, our low cash costs are a function of a robust infrastructure, low coupon debt, and top-tier G&A. This best-in-class margin, paired with our highly efficient operations, support the highest free cash flow per BOE produced. Turning to the next slide. Pioneer continues to offer an attractive investment case for shareholders through the combination of leading corporate returns and an inexpensive valuation. Pioneer's projected ROCE continues to exceed all other sectors within the S&P 500, as well as the majors and the broader energy sector. Pairing our strong return profile with our discounted valuation, we believe results in an extremely compelling and durable investment opportunity for shareholders. With that, I'll turn it back to Scott. Thank you. Going to slide 17. We published our 2022 sustainability report earlier this year, which highlights Pioneer's focus and significant progress on our ESG initiatives. We believe that these actions demonstrate our commitment and focus on ESG and further strengthens Pioneer's position as a leader in the industry. Our updated sustainability report can be found on our website, and we expect to publish an updated climate risk report later this quarter. Going to slide 18. We're excited to announce our participation in a wind development project on Pioneer's owned surface acreage, as well as the Concho Valley Solar Project. Both renewable energy projects will supply power to both Pioneer's field operations and Targa and Pioneer's jointly owned Midland Basin Gas Processing system. This renewable energy and the renewable energy credits generated will reduce our Scope 2 emissions and contribute to our emission reduction goals. The Concho Valley Solar project is currently operational, and the Hutt Wind development being built by NextEra is expected to be operational in 2024. We are pleased to have NextEra as a partner, and they have unmatched experience in developing wind and solar resources. We continue to evaluate further wind and solar development on Pioneer's own surface acreage in addition to these two initial projects. On the final slide, on slide 19, this is a summary of our key attributes that we have discussed today, which highlight our commitment to creating value for our shareholders. We will now open the call up for questions. Thank you, sir. If you would like to ask a question, you may do so by pressing star one on your telephone keypad. Please remove your mute function to allow your signal to reach our equipment. Once again, that is star one if you would like to ask a question. We'll go to our first caller, Neil Mehta with Goldman Sachs. Good morning, team, and thank you for all the great color here. I just wanted to turn to slide 11, and Rich, maybe you can expand on it a little bit more here. As you think about the path for when you expect well productivity to inflect, are you saying 2022 represents sort of the trough year and 2023 gets sequentially better, or do we have to look out further in that 2023 to 2027 stack to see that inflection? Yeah. Neal, great question. Yeah, it's really 2022 will be the trough. I mean, we've started and made the change immediately, but as you know, there's a planning process and permitting process. You'll start to see those wells spud in the first quarter and, you know, see the results of the higher thresholds as we move through the course of 2023. That's really the game plan going forward. I mean, basically it means every well in the program, we've got a higher bar, and it's gonna increase our program productivity. It's gonna increase our annual capital efficiency and result in higher free cash flow generation, you know, from that program into 2023. Thanks, Rich. Just to build on this, because it's gotten so much investor focus here over the last couple of months, what is the confidence interval about the improvement that you expect in productivity? What is the biggest risk to achieving this shift? You know, Neal, just given that, you know, having over 3,000 horizontal wells out there and having a big database of data, you know, I think it's very low risk. We're really just reshuffling the portfolio and bringing forward higher return wells and deferring some of the wells that were, you know, great wells, but you know, we got higher thresholds that we can hit, and so we've just deferred those and reallocated the capital. But the reality is, you know, we have high confidence that we're gonna achieve the results that we've laid out here. Thanks, Rich. Moving on to John Freeman of Raymond James. Good morning, guys. Morning. When we look at the 2023 plan, I know that y'all have got the vast majority of what y'all need sort of already secured. But when you just sort of think about the supply chain, just anything that you're seeing that's sort of loosening versus what areas are still remaining pretty tight when you sort of try to nail down your plan for next year? Yeah, John, I think you know we've you know pretty well got most of it you know tied up in terms of from what we need from an activity level. I mean just to give you a flavor of what 2023 you know kind of is gonna look like you know think about it as you know 24-26 rigs probably six-seven, you know, frack crews and of which you know three of those will probably be e-fleets over the course of the year as those come in is really what we're looking at you know as we look at 2023. You know that's gonna put our you know still early and we're still working on but you know growth in that mid 0%-5% range is where I'd you know kind of say given where we're at today. I don't really see anything from, you know, hopefully we'll see, which is the biggest inflation item we've had this year has been steel and casing prices. You know, having talked to a number of suppliers, you know, it sounds like that's flattening a bit. We'll see if that, you know, comes to fruition or not. Otherwise, everything else I think, you know, seems like we're not at the same level of inflation I think we've talked about before, and that we're still seeing, you know, 2023 relative to our program in 2022, you know, kind of that 10%- type inflation level. It could be slightly higher, you know, that's generally where we're seeing it. Hopefully that helps. Thanks, Rich. Absolutely. I mean, you know, you mentioned the three e-frac fleets that you've got that are gonna be delivered next year. I know that, you know, y'all have plans over the next couple of years to kind of move to nearly all electric in the field, and you've got some electric substations that are gonna be installed over these next few years. Can you just kind of talk to maybe the timeline of how all that stuff sort of plays out, when those, like, substations get installed and when, you know, realistically you could be, you know, nearly all electric in the field, just how that sort of timeline looks? Sure. I think, you know, 2023, I'd call a transition year. I think maybe I've mentioned on previous calls that, you know, this year we're virtually running, you know, everything on diesel. Next year, you'll see us as we get these e-fleets and some dual fuel engine and fleets going forward that will probably, you know, be a kind of that transition of part diesel, part CNG where we're headed. Then as these substations get built, we'll be able to start doing more of our operations. It won't be 100%, but more of our operations on high line power when we get to 2024, and then continue to, you know, move closer to 100%, you know, 2024, 2025, 2026 time period. I think that's the general evolution. You know, obviously the e-fleet, you know, activity, they come with, you know, longer life engines, you know, lower cost. It's, you know, better for emissions and better from a cost structure standpoint. You know, directionally, that's where we want to go. It's just gonna take time to get there. Really waiting on, you know, the build-out of transmission. If everybody does it, the power demand is gonna be higher, so we need power generation to come online as well. Great. Thank you. I appreciate it. Sure. Next, we'll hear from Doug Leggate of Bank of America. Thank you. Good morning, everybody. Rich, I wonder if I could just pick your brain a little bit on the, I guess, it's on the philosophy behind the, you know, the way you're gonna develop the asset going forward. Was this a surprise to you that, you know, the deferral, I guess, going back to the deferred targets, resulted in lower productivity? Is that something that you anticipated? I guess what I'm really trying to get to is when you think about your capital program, going back to the, for want of a better expression, cube development, are there any impacts on your capital expectation relative to the deferred target or the delayed target philosophy you had previously? Yeah. I'd say the, you know, the delayed targets, you know, have underperformed where we would have anticipated. They still have great returns. It's just we have better, you know, locations in our portfolio. As we've gotten those results over the course of this year, we've, you know, decided that's not satisfactory to us, and we wanna move forward with the higher thresholds. We've just reshuffled the deck, as I said earlier, and are moving to, you know, full stack, you know, basically across the field. You know, we'll defer those delayed targets till a later date down the road. Really that's been the game plan and the learnings that we've had this year as we get smarter and better as we move forward. To be clear, presumably you had the benefit of existing pads, so is there a capital implication for the change in the way you'll be developing going forward? It's probably small, Doug, but it's not a significant. You know, the pad cost is relatively small in the grand scheme of things. In some cases, we're still having to expand tank batteries. There, yes, to a small extent, but overall, I think you'll see that the new programs going forward, you know, are gonna be more capital efficient than we were in 2022, and which is the objective, and higher productivity and, you know, better free cash flow generation. Great. That's what I was after. Thank you. I'm sure Neal can't wait for my follow-up. It's my cash tax question, Neal. I wonder if, like, you could just give us a quick update as to the NOL position. It looks like deferred tax has started to trend a little bit lower over time, at least based on the third quarter. Any update there would be appreciated on your expected timing. Thanks. Yeah, Doug, I mean, first of all, good morning. Yes, that's right. We've essentially utilized our full NOL balance. You know, we've got a little bit that we'll utilize here over the next several years. For the most part, I'd model it as being utilized. You know, if you look at our federal cash taxes paid- to- date, based upon estimated taxes, it was based on a higher commodity price earlier in the year. You saw that change for Q4 guidance. Based on our current commodity price outlook, which is lower based on where we were earlier in the year, we believe we have minimal remaining 2022 federal cash tax obligations. If you kind of fast forward to 2023 based on the strip, we'll somewhere be in that, as I said before, mid to high teens. Understood. Thanks for the clarity, Neal. Appreciate it. Got it, Doug. Moving on to Scott Hanold of RBC Capital Markets. Thanks. Good morning. You know, maybe just stick with the budget or 2023 a little bit and just at high-level budget. I think you've gotten some pretty good color. When I think about sort of a 10%+ service cost inflation and then, you know, potentially adding a couple rigs, it kind of feels like a $4.4-$4.5 kinda overall capital range. Does that generally make sense? Can you talk about some, you know, pushes and pulls that, you know, may occur around that? Yeah, Scott. I mean, I think that's directionally right. I mean, we've talked about as we add, you know, those one-two rigs, you know, those, you know, with where they sit today are, you know, kind of $175 million, $200 million capital spend, and then you add the 10%, where we see that. So it, you know, from where we sit today at the $3.6 billion-$3.8 billion and add those increases to it gets you to that, you know, $4 billion, $5 billion general range. We're still working on it. Obviously, increasing the return thresholds has implications too, and in capital efficiency improvements. We're still working through all that. But you know, that I think directionally you've got it right. Okay. Appreciate that. You know, if I can go back to sort of the change in the drilling strategy and targeting higher return wells. Just you know, at a high level, can you give us some sense of you know, coming you know, into 2022 you know, when you laid out the program and obviously it wasn't as optimized you know, at the end of the day, but when you think about where you were targeting, was it you know, generally, you know, kind of going back to existing areas where you you know, drilled wells to whether earn acreage or for whatever reason and you know, drawing in some of the, I guess, other, you know, not as core STACK you know, part of a part of the portfolio. My kind of question kind of then, you know, thinks about like 2023 when you do the full-stack development, you know, is really less about, you know, drawing some of those, say, other than, you know, the best targets versus more the deferred completion impact. Yeah, Scott, I knew what I'd say, you know, when you got a million gross acres, we had our rigs spread out across the field to really, you know, handle all the things that you know laid out there. As we've moved that threshold higher, it just focuses more on areas that have those higher rate of returns. In general, that's gonna, you know, move probably a little more activity to the north across the field. That's really, you know, the allocation of capital here is really the focus in generating higher rates of return. That's gonna drive it. The longer laterals obviously has a higher rate of return, as we talked about on the call. There's a focus on that. We're gonna have over 100 of those wells in the 2023 program. That's really how we've gone about that selection. We're just, you know, we're still doing the full-stack. We're just, you know, prioritizing those wells that, or those pads and locations that have higher rates of return. I guess my question was more specific on that, the illustrations you have on Chart 11. In 2023, we can expect you targeting pretty much all of these six zones in the development program, right? Oh, absolutely. Okay. Got it. Thank you. Sure. Once again, as a reminder, if you would like to ask a question, you may do so by pressing star one on your telephone keypad at this time. Moving on to Charles Meade with Johnson Rice. Yes. Good morning, Rich and Scott and Neal, and to the rest of the team there. Rich, my first question is kind of along the same lines of most of these questions you've got this morning. I think I heard you say in your prepared remarks that you were a little disappointed or your 2022 program came in a little bit under where you thought. I wanna understand, is the change that you're making in 2023 essentially just reversing some of the changes you made for 2022 versus 2021, or is there another dimension to your evolution here? Yeah, Charles, I'd say it's more about, you know, just the allocation of capital and moving to higher return, you know, locations and areas. The returns that we are generating from the program in 2022 are still fantastic. I mean, so I don't want anybody to take away that they're not great returns. It's just, you know, the productivity came in a little less than we anticipated, and we wanted to rectify that and fix that, and we weren't satisfied with it. We've got a depth of portfolio that we can, you know, move things around. We've made those changes. Going into 2023, we're gonna drill, you know, just wells that have higher productivity and higher rates of return. That's really just, you know, what we're charged with from a capital allocation standpoint to make happen. That's where our focus is, and the team's, you know, highly focused on it. We're gonna, you know, execute that program going forward. Great. Thank you for that. The second, my follow-up is probably for Scott. Scott, I wanted to, you know, first off, congratulate you guys, they're buying back shares in the quarter. That's a great price that you guys were able to execute at. I just wanted to take your temperature and get an update from you on how you're thinking about the mix of buybacks versus variable dividends now. Now, as we laid out our program, you know, it's still heavily weighted toward dividends, which was all the feedback that we've been getting from our long-term investors over the last three years. We'll continue with that. We got the balance sheet to be very opportunistic, obviously, and we've shown that also, and we'll continue that also. Thank you. Next, we'll hear from Derrick Whitfield of Stifel. Thanks. Good morning, all. With my first question, wanted to ask on Waha [inaudible] understanding that you have limited exposure to Waha and the recent weakness is driven by maintenance with Gulf Coast Express and EPNG pipeline. Could you speak to your macro views on in-basin gas prices for 2023 and if [inaudible] tightness could lead to shut-in for some of your peers? Yeah, I mean, obviously, we've got pipelines coming and incremental compression coming. You know, as you can look at the forward curve on Waha prices out there, I mean, obviously they're, you know, trading at a discount to IMEX and SoCal and other places. You know, for Pioneer specifically, you know, I think we've talked about having about 25% in that range of exposure to Waha. You know, it's been a little bit higher because of the SoCal maintenance on El Paso being down. We haven't been able to move as many volumes out west as we would have liked. We've got incremental capacity on firm transportation coming in, you know, 2023 and then more in 2024 when Matterhorn comes on. We're also moving our Parsley and DoublePoint volumes that were on Waha. We'll be moving them out of basin, you know, in 2023, 2024 time period as well, as we take those volumes in kind. From Pioneer standpoint, you know, we'll have very little exposure, you know, kind of in that late 2023, 2024 time period at Waha is for us. You know, others, you know, for those that, you know, are smaller operators that don't have firm transportation, you know, obviously, until those new pipes come, they're gonna probably be getting discounted prices. You know, we'll see. I mean, I haven't seen any or forecasted seeing any shut-ins at this point, but that, you know, could be an ultimate result for some. But at this point, I'm not aware of any that are expected. That's great. Perhaps for my follow-up, I wanted to go back to slide 11 and just wanted to focus on your new economic threshold commentary. Could you help frame the degree of increase in returns you'd expect to see in that 2023- 2027 program? What percent of your 20+ year inventory falls into that category? Oh, yeah. Well, I mean, it's a meaningful increase from where we were in 2022 to what we're doing in that 2023, 2027 time period. Just given the depth of our inventory, we've got, you know, 15,000, you know, tier one locations out there. We've got a, you know, long runway to execute it at that same economic threshold that we've set to, you know, get these higher returns and higher productivity. You know, we're blessed to have the inventory we have, and we can execute this for a long period of time. Thanks. Great updates on your PPAs in 2022 well productivity. Oh, great. Thank you. Thank you. Next, we'll hear from Arun Jayaram with J.P. Morgan. Yeah, good morning. Rich or Scott, I was wondering if you could just help us understand the, you know, what the new IRR and return on investment thresholds are that you've shifted to? Yeah, Arun, I think it's just, like I said in the last question, it's really we've made a meaningful impact to increase them, and that threshold is really what we're building our 2023 and subsequent year programs on. It's a substantial shift, you know, I'll tell you that. You know, I think you'll see from that slide on 11 that's demonstrated there that the productivity is getting higher and capital efficiency therefore will be better, and our free cash flow generation will be better. That's really been the focus of the team as we've, as I said before, not been satisfied with our 2022 results, and we've made a, you know, a dramatic shift to improve that. Understood. Just maybe a follow-up, Rich. You know, just looking at some of the historical data in the Northern Midland Basin, you know, between 2017 and 2019, you know, Pioneer was completing about 85% of its wells in the Wolfcamp A and B intervals. That declined to, call it, the mid- to upper- 60s between 2021 and 2022. This year in 2022, you've done about 51% of your wells in the Spraberry and less than half in the Wolfcamp A and B. Is the plan on a go-forward basis to shift back to a higher mix of Wolfcamp A and B wells, you know, consistent with either previous years, or is it you're targeting new zones or new areas? I'm just trying to understand what shifts in early 2023? Yeah, I think it's more of a, you know, geographically where we're drilling. I think you're still gonna see us. I mean, as you know, across the field, you know, some zones are more prolific than others. You know, in general, for the 2023 program, I haven't looked at it, you know, specifically, but I think it's gonna be, you know, probably in that, you know, I think it's gonna be probably evenly split between Spraberry and Wolfcamp zones for the most part. You know, maybe it's slightly weighted towards the Wolfcamp zones as we look at that program, but it'll be area- specific and, you know, we're gonna maximize the returns by each zone, you know, given in the different areas across the basin. Great. Thanks a lot, Rich. Sure. Moving on to Matt Portillo with TPH. Good morning, all. Just a quick question around spacing design. You've had an extremely consistent spacing design on a horizontal perspective over the last couple of years, which has led to pretty consistent well results in the Wolfcamp in particular. I'm curious, as you've gone to full field development, are there any learnings on a vertical basis and how you guys think about vertical communication moving forward from a spacing design perspective? Matt, we continue to learn like everybody, you know, as we go. In general, I'd say our spacing really hasn't changed that much. I mean, it's still, you know, generally, you know, rule of thumb, you know, 800-900 ft spacing on the wells, you know, here and there. It's you know, different as we learn new things. If you think of, you know, broadly across our acreage position, it really hasn't changed over the last two or three years at all. I don't— Nothing big is how I'd characterize it. Perfect. Just to follow up on the differentiation between zones. Again, I know there's a lot of noise in the state data. The Wolfcamp results have generally been pretty consistent. It looks like the Spraberry may be a bit more volatility in the data set over the last few years. As you guys look forward into 2023 and that improvement in the overall development program, is part of this just some high grading occurring in the zones you're focused on in the Spraberry moving forward? Any color you can kind of give around just some variances we've seen in the Spraberry data over the last couple of years? Yeah, I think on the Spraberry data, you know, some of it will depend on whether they were full-stack development or, you know, single targets or delayed targets. You just get, you know, different data based on the vintage of when those wells were completed. You know, overall, on our program, you know, the threshold, you know, applies on a kind of a per zone, per well basis of how we've set it up. In areas where, you know, zones are less prolific, then we will drop those from the full-stack development. It's really just a case of we'll continue to maximize value in how we select the wells across each of those pads in full-stack. It's, you know, a full economic analysis that, you know, kind of gives the highest rate of return and the highest productivity that we're looking for. Perfect. Thank you very much. Sure. Next, we'll hear from Leo Mariani with MKM. Hey, guys. Just in terms of the 2022 program here, just looking at kind of the data in terms of well POPs to date, are we looking at kind of a pretty meaningful step down in the fourth quarter in terms of POPs? It looks like even if you do see that step down, you'll kind of still be at the high end of the range. Or do you think, just based on how the program's going, sounds like you're still running, you know, 20-something rigs, that maybe we'll get a few more POPs than the guidance here in 2022? No, Leo, I think you're right. I mean, the plan all along had us having, you know, less POPs in the fourth quarter. You know, we're gonna be, you know, roughly call it 25 POPs less in the fourth quarter than we were in the third quarter, just by the nature of the plan and just timing of how it's working out. You know, I wouldn't read anything other than that. It just, it was planned in timing, and that's where the program shakes out for Q4, and laid out in our guidance. Okay. That's helpful. Just wanted to ask a little bit on oil cut. Just kind of looking at the guidance here for fourth quarter, you know, high level, looks like you are expecting maybe the oil cut to come down slightly in terms of where it was in 2Q and 3Q. Just wanted to get, you know, a little sense in terms of, you know, why the cut's kind of been coming down during the course of 2022. Then in 2023, do you guys have kind of a rough estimate of what you think the oil cut might be? Do you see that maybe improving a little bit with kind of the high grading, you know, of the wells? Any color would be appreciated. Yeah, sure. No, you know, you're right. I mean, our general— our forecast has been in that 53%, 54% oil range. You know, I don't anticipate it changing much. It's come down over the years as we've, you know, just the GOR of these wells continues to grow. It hasn't changed our oil forecast at all, but the gas continues to come out of solution, so that's just part of what we've been getting. You know, in general, you know, I would think as you think about 2023 programs, it'd be in that same 53%, 54% range. Okay. Thanks, guys. Sure. Next, we'll hear from Neal Dingman with Truist Securities. Morning, All. N ice quarter. First, a quick one, guys, on the continued development. Scott, I think last time you mentioned on the call the tackling a couple of gas wells— next year you're targeting a couple of gas wells in Woodford, Barnett. Could you just say your thoughts on that? Obviously, gas continues to do very well. I'm wondering, is that still the plan and sort of the rationale behind that? Yeah, Neal, it's Rich. Yeah, we still plan on testing a couple wells in each of the Woodford and Barnett zones next year. That's, you know, part of what we're planning for. We expect, you know, those wells obviously to be, as they're deeper, to be gassier. We're really, you know, we know we'll find resource there, and so it's really just what's the productivity of those wells. Given where gas prices, you know, are maybe lower at Waha today, but you know, where we expect them to be longer term in the forward curve, we just wanna understand that, what that resource is. We think it's worthwhile to, you know, spend some capital next year to test those zones. Then we'll see what the productivity looks like and go from there. Makes sense. Rich, while I have you, maybe just a follow-up is just what do you all think. I know you talked about DUCs or the POPs going down a little bit. DUCs at the end of the year, will it just sort of be a normal level, or what could you comment on how many you would have? I didn't know if you'd think about having a little bit more than normal because of the timing and, you know, might help a little bit in starting in 2023? Yeah, I don't think it'll be materially different than just our normal working capital of what I'd call DUCs that are, you know, pads that are ahead of the frac fleet. Nothing that is gonna be a big change from where it's been through most of the year. It'll be business as usual is how I'd put it. Okay. Very good. Thank you all for the time. Sure. Thank you. Next, we'll hear from Bob Brackett with Bernstein Research. Yeah, good morning. A question coming back to the relative underperformance of the delayed target strategy. Could that just simply be that the frac heights in the initial wells exceeded their target zones and you're getting some contributions from those delayed targets? What's the responsibility of that? Yeah, Bob, I think, you know, there's definitely, you know, some level of communication. We've seen that as the reservoirs we've, you know, come back and done those delayed wells. That's impacted, you know, the productivity some from those wells that, you know, we didn't anticipate. You know, at the end of the day, like I said earlier, the returns have been still very, very strong returns on those delayed wells. There's still, you know, plenty of resource there. It's just, you know, we can get better returns by moving to the full stack in other locations. That's clear. The other question would be, you know, clearly your opportunistic share repurchases have been effectively retiring shares at a low price. How do I respond to the buy side that argues, "Well, Bob, you've got a $283 target price. Pioneer, who knows more about Pioneer than anyone, is buying in the 220s. So n o, thanks. We run NAVs on all of our assets, and I think it's better. We're always gonna buy a little bit each quarter, but I'd rather be stronger and try to buy the stock at a discount. That's just the way we are, so. Okay. Appreciate that. Bob, you know, as a follow-up to that, look, in terms of the conversations that we've had with our shareholders and their desired method of return of capital has been primarily, as we've discussed, the base dividend combined with the variable dividend, you know, that takes you to 80% of free cash flow. You know, where the majority of the free cash flow is spoken for. That being said, even over and above that, we've been very opportunistic and not shy to deploy that capital incrementally to buy back shares. We do step into the market and repurchase equity. It's just that the return of capital, as it's been communicated to us by our shareholders, there's been a preference for the base plus the variable. That's, you know, that's a big part of that rationale, of course. You gotta look at the total stock. You gotta look at the total stock return. We paid out $26. People, when you look at a total — TSR, a lot of charts don't show that $26 payout. You just gotta think about that also, Bob. Yep, very clear. Moving on to Phillips Johnston with Capital One. Hey, guys, thanks. Rich, just to follow up on Arun and Matt's questions. It sounds like there's clearly a geographic mix shift element to the new approach. If I heard correctly, you aren't necessarily changing the mix of zones within any given area. There's no real mix shift towards Wolfcamp and away from [Spraberry], but it sounds like you are just gonna sort of be more selective within a given section. Is that correct? Yeah, I think, you know, just given our expansive acreage position, that we'll, you know, move things around that, you know, maximize the return thresholds by the geographic area where we're in. Yeah, as I mentioned, I think, you know, there's definitely, you know, we're gonna go to locations and areas that have the highest rates of return, and, you know, that will, you know, move to a certain extent a little bit north. Okay. Is that gonna wind up, I guess, yielding fewer wells per section? No, I don't think it's changing. I mean, we're not changing, like I said earlier, the spacing on the wells anywhere. It's just, you know, going to those higher productivity areas that we're in, therefore has higher rates of return that we're targeting. Like I said, it's not changing our depth of inventory or the, you know, how long it's gonna last. It's just what we're drilling today versus what we're drilling tomorrow. We've just deferred some, you know, things that we had in the portfolio that we're gonna push to, you know, back in time and bring some things forward that have higher rates of return. Yeah. Okay. Thanks, Rich. Sure. We have time for one final question, Jeanine Wai with Barclays. Hi, good morning, everyone. Thanks for taking our questions. Thanks, Jeanine. Our first question is on the renewables update that you provided. Just wondering if you could give a little bit of commentary about any capital requirements that come with those projects and anything around maybe the economics or the cost of the electricity that you're gonna be buying relative to what you would be paying if you didn't have these agreements? Sure, Jeanine. In terms of capital, I mean, NextEra is developing the project on our, you know, surface location and on the Concho Valley one, that's being developed by them. No, you know, capital from our side that's gonna be investing in that. We are signing, like, as you mentioned, power purchase agreements to, you know, take that power. You know, based on where the forward curve on, you know, the electricity market looks like, you know, these are at favorable prices to that. You know, we're excited to get those projects on it and, you know, get the benefit of that power purchase agreement pricing. They're good pricing is the way we look at it. Then on top of it, we get, you know, the renewable energy credits that come with that can reduce our Scope 2 emissions. Overall, we think it's a, you know, two great projects and look forward to doing some more. Okay, great. Thank you. Then, as the second question, I apologize for going back to the full stack development topic and if I miss this in another question. You know, we love our fun with maps. Just wondering if you have a rough estimate of how much of Pioneer's overall acreage is virgin, would qualify for more virgin stack development versus, you know, something that would be more impaired? Thank you. Jeanine, I don't have a rough estimate. I mean, just given the size and scale of our footprint, you know, I would say there's still a significant amount of virgin, but I don't have a percent that I could quote to. I would just be guessing, and I don't wanna do that. We can probably find it, but I don't know that off the top of my head. Okay. We thought we'd try. Thank you. Thanks, Jeanine. That's all the time we have for questions today. We'll turn the conference back over to Scott Sheffield for any additional or closing remarks. Again, thank you very much for participating. Everybody, over the next couple of months, have a happy holidays and travel safely. Thank you. That does conclude today's conference. We thank you for your participation. You may now disconnect.