Welcome to Pioneer Natural Resources' second quarter earnings conference call. Joining us today will be Scott Sheffield, Chief Executive Officer, Rich Dealy, President and Chief Operating Officer, and Neal Shah, Executive Vice President and Chief Financial Officer. Pioneer has prepared a presentation of 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, then select Quarterly Results. Today's call is being recorded. A replay of the call will be archived on www.pxd.com through September 1, 2023. 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 the 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 Chief Executive Officer, Scott Sheffield. Please go ahead, sir. Thank you, JL. Good morning, everyone. It's great to be with you today. Before we highlight Pioneer's strong second quarter results, I wanted to briefly speak to the current macro outlook and its impact on oil prices. As you all know, crude has been range-bound between $65 and $80 over the previous several months, and has been suppressed by SPR releases, recessionary fears, and weak economic data from China. The recent upward move in oil prices reflects the expectation for tightening supply-demand fundamentals in the second half of this year. The major contributors to this include: the Fed's success in managing inflationary pressures and preventing a recession, likely resulting in a soft landing for the U.S. economy. China actively taking measures to bolster its economy through stimulus programs. Limited U.S. oil shale supply. The end of substantial U.S. SPR releases, which has resulted in a 40-year low inventories. This outlook is further supported by Saudi Arabia's production cuts and ABS's preference to stabilize Brent oil prices at 90 or higher. I do expect Saudi to extend their 1 million barrel a day cut they initiated July 1st toward the end of 2023. I see these factors leading to demand outpacing supply, resulting in global inventory draws during the second half of 2023. The expected demand increase, combined with the underinvestment by industry over the last several years, are both supportive for oil pricing in the $80-$100 range for the remainder of 2023 and through 2024. Turning to Pioneer's performance, we delivered excellent second quarter results, thanks to the safe and highly efficient operations of the Pioneer team. I applaud the great work and efforts of all of our employees. I know that Rich and the team's focus on top-tier execution will continue to deliver strong results throughout the year, as highlighted in the presentation that Rich and Neal will speak into more detail. Again, it's great to be with you all today. I will now hand over the call to Rich. Thank you, Scott, and good morning. I will begin on slide 3. As you can see, Pioneer delivered an excellent second quarter with oil production near the top end of our guidance range. As we expected, we are seeing improved well performance relative to 2022, and the teams continue to operate at a very high level. As a result of our strong well productivity and highly efficient operations, we are increasing full year 2023 production guidance, while simultaneously lowering our full year 2023 capital guidance to reflect our intentional activity reductions and some deflation. This combination of higher production and lower capital drives an improved 2023 plan and further enhances Pioneer's capital efficiency. Along with these solid results and strength in full year outlook, we continue to return significant capital to shareholders, with 75% of our free cash flow being returned through, excuse me, our base plus variable dividend and opportunistic share repurchases. Additionally, we remain committed to sustainable and socially responsible operations, as evidenced by our newly established methane intensity target of 0.2% or less in 2025, in accordance with Oil and Gas Methane Partnership 2.0 initiative. Additional details on our progress and continuing efforts can be found on our recently published 2023 sustainability report. Turning to slide four, the team's continued focus on execution resulted in strong second quarter production, with oil production near the top end of second quarter guidance at 369,000 barrels of oil per day, and total production exceeding the guidance range at 711,000 barrels of oil equivalent per day. Our significant free cash flow generation is bolstered by our strong production, top-tier price realizations, and low horizontal lifting costs, which drive our best-in-class margins that Neal will talk about further later in the presentation. Turning to slide five, as I highlighted on the first slide, we are raising our full year 2023 production guidance, while concurrently decreasing our drilling, completions, and facilities capital guidance. The midpoint of our oil guidance increases to 369,000 barrels of oil per day, and the midpoint of our drilling, completions, and facilities capital budget is now lower by $125 million from our original 2023 outlook. This improved 2023 plan is driven by strong well productivity and highly efficient execution by our operations teams.... resulting in a more capital-efficient program. Turning to slide six, as seen through the company's increased full year 2023 production guidance, Pioneer expects to deliver oil production ranging from 364,000 to 374,000 barrels of oil per day, and total production ranging from 697,000 to 717,000 barrels of oil equivalent per day, consistent with our investment framework that delivers moderate annual production growth of up to 5%. Our reduced drilling, completions, and facilities capital budget is expected to range between $4.375 billion and $4.575 billion as a result of our reduced activity and operational efficiencies, which are being driven by longer laterals, simul-frac operations, and utilization of localized sand mines, to name a few. Our exploration, environmental, and other capital expectations remain unchanged. As we previously discussed, this capital is allocated to four exploration wells targeting the Barnett Wood formations in the Midland Basin, adding infrastructure to further electrify the field, allowing us to move more of our activity to the grid, as well as our continued appraisal of our enhanced oil recovery project. Our 2023 rig count is now expected to average 23-25 rigs due to our intentional activity reductions. As a result, the projected number of wells placed on production during 2023 now ranges from 490-520. Turning to slide Seven, looking at the chart on the left, as expected, our 2023 average and average well productivity is trending significantly above 2022 and is expected to surpass 2021 levels over the first 24 months of production. Our strong 2023 production, paired with robust execution, underpins our increased full-year production expectations. We are focused on full-stack development, which improves long-term recoveries and optimizes returns. As seen on the right, Pioneer has one of the deepest inventories of low break-even, high-margin locations amongst our peers. Overall, as we've discussed in the past, we have roughly 15,000 high rate of return locations with low break-evens. This deep inventory of highly productive wells enables our best-in-class development for decades to come. Turning to Slide 8, as part of our low break-even inventory, Pioneer has an extensive inventory of extended lateral length wells. This slide highlights the benefits of long lateral length development, both lower costs per lateral foot and increased production levels. 15,000 foot lateral length well development generates significant efficiencies in both drilling and completions. These developments require fewer wellbores, along with less drilling rig and frac fleet mobilizations. The combination of these benefits results in a capital savings of approximately 15% per lateral foot. These capital savings, paired with optimized artificial lift, have further increased returns, with IRRs increasing by more than 35% when compared to 10,000 foot laterals. Our strong well results and artificial lift refinements have improved the average IRR uplift to 35%, well above our previous estimate of 20%. Our highly contiguous acreage position contains more than 1,000 future locations, with 15,000 foot or longer laterals. We expect more than 100 of these wells to be placed on production in 2023, including some wells that have lateral lengths in excess of 18,000 feet, further improving returns. Our land team continues to do a great job to optimize our land position by actively working trades to strategically increase our significant long lateral inventory, again, demonstrating the benefits of Pioneer's unique contiguous acreage position. Turning to slide nine, Pioneer's completions efficiencies are industry-leading, with Pioneer's average completed feet per day being approximately 80% better than peers and U.S. majors. These peer-leading efficiencies are a testament to the hard work and focus of our teams. In addition to our focus on operational efficiencies, we are driving additional capital savings through the utilization of localized sand mines and simul-frac technology. We are now operating three full-time simul-frac fleets, which continue to be a major contributor to our high efficiencies, delivering average cost savings of $200,000 per well. Pioneer began utilizing a second localized sand mine during the second quarter. These localized sand mines reduce road traffic, lower CO2 emissions, and provide average capital savings of $200,000 per well. Consistent with our commitment to sustainable operations, we expect 100% of our completion fleets to be either electric or dual fuel-powered in the third quarter of 2023, allowing us to both reduce emissions and capture fuel cost savings. I will now turn it over to Neal. Thank you, Rich. Good morning. Turning to slide 10, Pioneer continues to return significant capital to shareholders through dividends and opportunistic share repurchases, as outlined in our investment framework on the left chart. Consistent with this framework, as illustrated on the right, Pioneer returned $557 million of second quarter free cash flow through a combination of our strong base dividend, variable dividend, and opportunistic share repurchases. Our strong third quarter annualized dividend yield of 3.3% continues to substantially outpace the average S&P 500 yield of 1.5%. We believe this return of capital framework, paired with annual oil growth of up to 5%, provides significant value for shareholders. Turning to slide 11, Pioneer continues to generate peer-leading margins through the combination of our top-tier price realizations and low cash costs. Pioneer's margin benefit from our diversified marketing strategy. In fact, I will highlight the strength of our gas marketing strategy in greater detail on the following slide. Our compelling cash costs are underpinned by our low G&A, interest expense, and bolstered by the teams focused on driving low, peer-leading operating costs per BOE. During the second quarter, we achieved operating costs that were approximately 20% lower than the same period in 2022. These best-in-class margins support our strong free cash flow generation. Turning to slide 12. As I introduced on the previous slide, Pioneer's strong price realizations benefit from our diversified gas marketing strategy. This strategy provides access to the premium West Coast and Gulf Coast markets, and reduces our exposure to the localized Waha market, which regularly trades at a discount to the major end gas indices. As seen on the graph to the right, during the first quarter, Pioneer's realized gas price was nearly 20% higher than that of peers. Thus far, based on industry-reported second quarter results, we have maintained our strong price realizations relative to peers. We employ a multi-year planning and strategic approach to our marketing strategy that has provided us access to these premium gas markets. As noted in the graphic in the lower left-hand corner, Pioneer expects to further increase the percentage of gas that is sold out of the basin from approximately 70% today to approximately 80% in the second half of 2024 when Matterhorn comes online. Turning to slide 13. The graphic on the right illustrates the free cash flow generative power of our long-term investment framework, which delivers annual growth of up to 5%. Pioneer's high-quality assets, high margin production, and moderate oil growth are forecasted to generate five-year cumulative free cash flow of $27 billion, assuming an $80 WTI oil price, or approximately 50% of our enterprise value. Even at $6 WTI, our program is expected to generate approximately $13 billion in cumulative free cash flow over the next five years, which demonstrates the resiliency of our program even at lower oil prices. This slide essentially represents the culmination of what we've discussed with you here today. Pioneer's strong price realizations, our peer-leading margins, our deep inventory of highly productive wells, and improved capital efficiency, all elements contributing to the result, durable and compelling free cash flow generation at various commodity prices. With that, I will hand things back to Rich. Thanks, Neal. I'll resume on slide 14, which includes highlights from Pioneer's recently published 2023 Sustainability Report. The company has continued to make progress towards our emissions reduction targets. As I mentioned before, we are proud to announce that in accordance with OGMP 2.0 initiative, we established a methane intensity target of 0.2% or less in 2025, which places Pioneer on path of achieving the OGMP Gold Standard designation. In support of this target, we have recently completed the installation of fixed methane sensors, monitoring 80% of our gas production. We also continue to retrofit pneumatic controllers and conduct aerial methane surveys across our assets. These methane reduction efforts resulted in a 64% reduction in methane intensity during 2022, compared to our 2019 baseline. In addition to our methane reduction efforts, our Huttwinde Renewal Project is on track to begin operation in early 2024. We expect this project to not only reduce our emissions, but also provide electricity at a very competitive cost to our operations. We are also making significant progress on field infrastructure, will allow us to move more of our drilling, completions, and production operations to electric power, further reducing our emissions footprint. Our progress and commitment to sustainable and socially responsible operations is outlined in detail within our sustainability report, which can be found on our website. I conclude on slide 15, where you can see our foundational elements of Pioneer strategy, which supports our commitment to creating value to shareholders. With that, JL, we're going to open up the call, or happy to open up the call for questions. Thank you. We'll now begin the question and answer session. If you do have a question, you may press star one on your telephone keypad to queue up. If you wish to withdraw yourself from the queue, simply press star one again. one moment for your first question. Your first question from the line of John Freeman of Raymond James. Please go ahead. Good morning, guys. Morning, John. It's really nice seeing the well productivity trends continue. I guess I'm just thinking, you know, in the past, when you all talked about the kind of that long-term 0%-5% growth range, and you all talked about adding 1-2 rigs a year. Just based on what you're seeing from a productivity, capital efficiency kind of improvement, if that's sort of changed how you all view kind of the necessary rig add to accomplish that? I guess, said differently, is that that second half 2023 activity run rate, is that, you know, something close to what we should assume as a base case for for 2024? Yeah, John, yeah, it's probably a little early to talk about 2024 just from a total standpoint, but I would say as we look at it going forward, we you know, see production in that upper half of our 0-5% range is where we'll target production for 2024 based on the day. In general, as we've talked about, as you outlined, you know, it takes 1 - 2 rigs to, you know, grow at that, that level. As you point out, you know, we've had significant, you know, growth and productivity in 2023, and so that should make 2024 very capital efficient. To me, it probably means that we're at the lower end of that 1 - 2 rigs, or maybe even potentially flat. You know, more to tell, you know, the teams are doing a great job on execution and driving efficiencies, which really allows us to do more with less activity with less rigs and less frac fleets. Great job by the team. Thanks, Rich. My second question on the, the $125 million CapEx reduction at the midpoint, is it possible to break that down between how much is just due to the, the reduction activity, versus maybe other cost savings that you weren't originally expecting? Yeah, most of it is really driven by activity, as you saw by the reduced average one rig down and then 10 to less POP. That's the biggest contribution. You know, clearly, we are seeing some deflation, mainly on steel projects or casing and tubular goods, some on fuel and chemicals that are, you know, helping. You know, we've heard commentary about rig rates and frack fleet rates coming down. From what we've seen, those are mainly on spot rates, and they're on what I'd call, you know, less efficient rigs and Tier two equipment on the frack side. When we look at our contracts, just given our size and scale, our contracts today are still below where those spot prices are being quoted. I just think it's just a testament to our team. I don't really see a lot of change in the back half of this year. Maybe it's impact 2024, but, you know, today we're still in a, in a favored price on pricing other than steel and getting the benefits of steel and fuel. Thank you. Your next question comes from the line of Neil Mehta of Goldman Sachs. Please go ahead. That's a good job, comments. Good to see the productivity improvements coming through here. Rich, it's been a couple of months since the CEO announcement was made. We'd just love your perspective on two or three of the most important strategic priorities that you're talking about within the business, and how can we benchmark your success on executing against this? Yeah. Thanks, Neal. Well, I, I think you're seeing it demonstrated in the quarter. I mean, our focus is on execution and delivering what we set out to deliver at the beginning of the year. I think you're seeing, you know, the great work of, you know, our 2,000 employees delivering the results with the improved well productivity, driving down capital costs, and increasing efficiencies. That's really, you know, how we're measuring ourselves internally, is delivering what we set out to at the beginning of the year. You know, I think this quarter is a, a good example of what we hope to do, and it's really just a, a testament to our inventory of deep, high-quality wells that we can do this for a long time into the future, so for decades, just given the depth of inventory we have in the Midland Basin. Yeah. Thanks, Rich. The follow-up is just return of capital. You were 75% of free cash flow, went back to shareholders, and was balanced between the base dividend and share repurchases. Maybe you could talk about how you're thinking about the share repurchases or the variable dividend of the flywheel of the return of capital, and is 75%, the right number here, or should we focus on the at least 75%? Hey, Neil, it's Neal as well. Look, you're, you're precisely right. The return of capital framework really provides us that, that flexibility to allocate capital between variable dividends and opportunistic share repurchases, really based on where we see the best value for shareholders. You know, also, considering the diverse shareholder base that we have, which includes income-oriented investors as well, we really kind of employ a balanced approach to assessing the variable dividend versus opportunistic share repurchases. I think going forward, we anticipate a, you know, a component of each on a quarterly basis, but it'll shift, quarter to quarter, really based on where we see value, really stepping in the market and being an opportunistic, as we were this, this past quarter. You know, at 75% in terms of return of capital to shareholder, that's kind of, as we talk about it, based on the framework, kind of a firm number. But, you know, we have said that we'll utilize the balance sheet if we, if we see the opportunity and, and the, and the, the, the chance to really step into the market if, if the stock drops precipitously. I think that's, that's always a, a definite possibility. Thank you. Your next question comes from the line of Arun Jayaram of JPMorgan. Please go ahead. Yeah, good morning, Scott and Rich. My first question is you guys announced your plans to raise your IRR thresholds on the third quarter call last year. I was wondering how much of the well productivity gains are, are reflected in your results of the first half of the year, and how much do you see is, is still on the come? Maybe you could give us a sense of, you know, your secret sauce or what you're doing to kinda bolster your, your well productivity at this point. Sure, Arun, a great question. I, you know, I'd say it's what we've talked about in the past, is we've, you know, are really focused on developing our full-stack development across our inventory thing, and so that you've seen that, that move. Then you've also seen us, you move to the 15,000 foot laterals, which is something unique to our acreage position, that we have a deep inventory of those. So I think it's the combination of those things that are really driving the productivity results. It's as we expected coming into the year. You know, it's probably happened a little earlier in the year than we anticipated, but it's still, you know, something that the well results are fantastic. The team's done a great job ohttps://editor.inflexiontranscribe.com/static/media/icon-stop.c66f93825c3f48c23a40e2e9d93da074.svgn execution, and something that I think by the, the updated guidance, you can see will continue into the, the second half of the year. That's really the, you know, the plan. It's not anything fancy. It's just, you know, developing our, our great acreage position with full-stack development, which I think is maximizes recoveries and, and improves and is the optimal way to get the highest rate of return. Great. My follow-up, Rich, you're taking down your 2023 CapEx by about 3%, below expectations, about the $125. I was wondering if you could give us a sense of if you have any thoughts on 2024 CapEx or how to think about 2024 CapEx, given some of the efficiency gains, deflation, and the fact that you could add 1 - 2 rigs to kind of deliver that 0%-5% growth? ... Yeah, yeah, I think 2024, as I mentioned on John's question, is gonna be really highly capital efficient. I, I just think the growth that we're showing in 2023, when you think about growing in the upper half of our 0%-5% next year, you know, you basically got a good jump start in it, just with the, what's happening in 2023. We see 2024 as very capital efficient. Hopefully, it's even better with some deflationary pressure on, on the cost side of things. It's, it's too early for me to kind of predict what that's gonna look like, just given where oil prices are and where oil prices, you know, may be headed the back half of this year. We'll have to wait and see, but it, it's something our supply chain team's working on day in and day out to see how we can, you know, make sure we have favorable pricing going into 2024. You know, all said, I think you're right, that it's, it's gonna be a very capital efficient program in '24, based on what we know today. Thank you. Your next question comes from the line of Scott Gruber of Citigroup. Please go ahead. Yes, good morning. You guys have been adding simul-frac crews and e-frac crews this year, and your completion efficiency is really impressive. Is it still getting better, and is it, and, are the gains sufficient, you know, such that, you could possibly, drop a frac crew on a, on a normalized basis? You know, Scott, it's something that the teams, you know, are working on every day to, you know, drive that efficiency. I think, you know, it'll be harder for us to add another simul-frac just because of the movement of logistics, mainly is the biggest thing. It's not to say the teams aren't, aren't looking at it, but we have gotten more efficient. The teams have, you know, are really, you know, having less non-productive time, being more efficient on location. So, you know, that's the ideal goal is to do that. So, you know, ultimately, that's the focus of the teams, is to, you know, continue to improve that efficiency longer term. You know, there's other things, you know, as like on the localized sand mine, would be another thing that we're working on. We've got 2 of those. We're looking at a third one in 2024 that would, you know, reduce those well costs that it could be applied to in 2024. There's things like that the teams are continuing to work on that, you know, hopefully will allow us to, you know, either further improve well costs in 2024. Got it. Just on a, you know, another initiative to, to reduce well costs, and improve capital efficiency, the 15,000 foot program, I, I think it consisted of around 100 wells this year. You know, as you start to plan for next year, how will, how will that figure change? Is it gonna go up meaningfully? Yeah, I think it'll-- the goal is for it to go up. They're, they're still planning on what that looks like. You know, how meaningfully it goes up is really just balancing, you know, where we're at in the field and logistics to go with it and timing. You know, given the higher rate to return, you know, obviously more of those we can move into the front of the program, the better. Then really, the less wells we drill and less activity we have as well to get the same production, you know, target. Definitely a great advantage to the company and something that we're working on, and so modestly increase in 2024, I'd say today, but, you know, it's still a work in progress. Thank you. Your next question comes from the line of Matt Portillo of TPH. Please go ahead. Good morning, all. Just to dig in a little bit, obviously, the, the well improvement year to date has been fantastic. I was curious, as we look at the, the state data, the Spraberry, in particular for you all, have seen a big improvement. I'm curious if that's due to the high grading dynamic for the 2023 program, the spacing design changes you guys have implemented, or, or any other factors that you could point to that is really driving that productivity gain for the Spraberry? Yeah, Matt, I, I, you know, I don't have the specifics on, on that zone, but, you know, I'd say just more broader picture, you know, the really, the full stack development, we're seeing it across all zones. I think when you look in the, the state data that, you know, the improvement by developing on a full stack is just, you know, a better way to maximize recoveries and returns. So that's really been our, our focus. In terms of, you know, the 15,000 foot laterals, we're doing those across all zones as well. You know, I just think it's, you know... I don't know the specifics on the Lower Spraberry, in particular, but, you know, overall, the well performance has been fantastic, as you can see from the data. Perfect. Just as a follow-up, maybe for Scott Sheffield, I know you spend a lot of time looking at the broader macro environment. We've seen over the last two years, the private operators driving a huge amount of shale growth, given the sugar high on the development program. Just curious, your views on how the industry might evolve over the next couple of years as it relates to private operator inventory management and also supply growth moving forward, as we've seen a pretty significant cut to the rig count? Yeah, I think you're starting to see it in the U.S Lower 48 production, too, with the recent EIA data. It's definitely slowing. People are definitely gonna run out of inventory over the next several years. Most people, except for a few of us, like Pioneer and other 2 or 3 others in the Permian Basin, which will lead to, it should lead to, you know, extreme consolidation. That will continue. It's all, it's all based on inventory. There's private equity is running out of opportunities to divest. Thank you. Your next question comes from the line of David Deckelbaum of Cowen. Please go ahead. Thanks, Rich, Neal, and Scott. Appreciate the time this morning. A lot's been covered already, but I was curious, just going back to the slide where you talk about this well productivity that you're, you're estimating this year and the gains. You do see, I guess, some greater outperformance as you get into the longer life of the well, beyond two years. I guess I'm curious, one, you know, what have you seen to date, I guess, in, in the initial like three to six months of wells that you've put online this year relative to the program last year and the year before, in terms of just percentage of outperformance on a, on a per foot basis? Yeah, David, great question. That graph really includes, you know, actuals to date, and then the forecast over that 24-month period of what we anticipate. I, I'd say the real, you know, benefit is, as we've, you know, did these artificial lift refinements and really customize those artificial lifts by, by zone and by area, that that's really, you know, paid dividends and just drawn down the wells quicker, allowing to bring that productivity forward. You know, we've just seen the benefits of that, and you can see it in the state data of, you know, the higher productivity from those wells by just, you know, really managing the artificial lifts and customizing it where appropriate. I appreciate that. Then, maybe just a little bit more color on that side. As you move more to 15,000 foot laterals, you saw the capital guidance coming down this year, but how is that changing some of the spend, either per pad or per area on facilities like water infrastructure? Is that something that should tick up with sort of completion intensity or lateral length intensity over time? Or is that something that's gonna be trending in a more positive direction in 2024 and 2025? Yeah, I think longer term, it's gonna... I mean, 2024, 2025 is probably not too different than what it was in 2023. Longer term, as more of the basin gets developed, you know, we can use existing facilities and infrastructure and take advantage. That capital should, you know, moderate over time, as we've talked about. The 15,000 foot laterals, in terms of the facilities that go with those, yeah, they've got a little more volume to handle, but the economics are so strong, as you can see, that it's very worthwhile. You know, they're in and around areas where we're gonna add additional wells in time, too. You know, overall, like we've talked about, it's all pointing to more capital efficient operations longer term. Thank you. Your next question comes from the line of Scott Hanold of RBC Capital Markets. Please go ahead. Yeah, thanks. Just another question on the productivity improvement and, you know, specifically with the 15,000 foot wells. When you look at the initial performance and what you're seeing over a longer dated time, do you see those producing as prolifically on a, you know, kind of productivity per foot basis? Or is it more of a shallower decline longer term? What is the, I guess, differential between what you're seeing on the longer laterals versus, say, a standard 10,000 foot lateral? Yeah, great question. Really what we're seeing with the artificial lift and modifications is that, you know, they're maybe not quite, but almost essentially, you know, basically 50% better like you'd expect from a 10,000 foot lateral on a, on a productivity per foot. There- sometimes we're, you know, limited by the fluid we can move until there's a, a short period where they're flatter. Because of, you know, these bigger ESPs, high high-pressure gas lift, you know, we're moving more fluid volumes, and therefore drawing them down quicker and getting, you know, basically on that, what I'd say, a proportionate curve to be a 10,000 foot lateral. Okay. [audio distortion]. Yeah, no, that, that's helpful. Going back to shareholder returns, maybe this one's for Neal Shah. How do you think about the fixed dividend? Obviously, you gave some pretty good color on, you know, that, you've got a balanced investor base, some like income and obviously some like buybacks. What is your goal on that fixed dividend moving forward? Like, where do you want it to be? How competitive in the growth kinda, you know, pace of it? Yeah, that's a great question, Scott, and good morning. You know, you've seen our, our commitment to a strong and growing base dividend. We've, you know, we've increased it consistently over the previous six years. Recently, just this last previous quarter, we increased it by an additional 14%. Our, our current base dividend, if you, if you think about the, the total yield package, we're at 3.3%, which outpaces the S&P 500 at 1.5%. We believe the base dividend is, is extremely important and, and an avenue of return to our shareholders. Going forward, I would expect that base dividend increase roughly commensurate with our production growth. Again, it's, it's a very important return avenue for us in terms of getting that capital and cash back in shareholders' pockets. Thank you. Your next question comes from the line of Charles Meade of Johnson Rice. Please go ahead. Good morning, Rich, Scott, and Neal, and, and to the rest of the, the PXD team there. Rich, I, I just have, just 1 question for me, and it's, it's about the, it's about the reduction of the rig, and the average rig count for the year. You, you reduced the range by one. Am, am I right to think that that, you know, since that's happening for, for back half, for the back half of the year, that you're actually reducing the, the rig count on the back half of the year by two? Maybe tell me if that's the right way to think about it and give a little more color if, if those rigs are already down, or, or if this is it's gonna, you know, happen in the next couple of months, or just more color there, if you could? Yeah, Charles, you know, good question, and you're spot on. I mean, the average rig count is, is for the, the year. You know, we have, you know, rig count ebbs and flows just with our activity levels, so it's not always stagnant. We have some that roll off and bring ones on. Directionally, you're right, that, you know, we have dropped, you know, multiple rigs at this point, really reflecting that average rig count, count by one. You're exactly right. Got it. Thank you. You're welcome. Your next question comes from the line of Neal Dingmann of Truist Securities. Please go ahead. ... Morning, all. My first question is just on well costs. I'm just wondering, given the well, obviously, well productivity everybody's been talking about, certainly noticeable for you all, and potential deflation, I'm just wondering, you know, how would you all have us consider about well costs maybe through the end of the year, in particular in 2024? Yeah, it's still early for 2024, so I hate to get there, but, you know, obviously, with moving the capital down, our well costs are. You know, you can take that $125 million and, and divide it out, and, you know, that's what we're seeing in terms of a decrease in, in well costs, going forward because of the just the improved program. Like I said, you know, the, the key kind of deflationary things that are out there are really OCTG, steel, and fuel and chemicals that we're seeing. We're, we're, you know, seeing things on a few other things, but that, that's where the majority of the savings is coming from, and then just reduced activity like we talked about. Overall, trending the right way and, and hope to see those continue, and everybody's working on that. Yeah, it sort of seems like it, Rich. Secondly, maybe for Neal, just on the balance sheet, and shareholder return. You know, you all done a great job on the shareholder return that's been talked about. Looks like net debt went up a little bit, so I'm just wondering on a go forward, you know, how do you balance all those things? I guess maybe, Neil, I'll ask more specifically, should we think about net debt starting to go down more materially through the end of the year and into next year? Yeah. Yeah, that's a good question. I mean, you know, in, in a higher commodity price environment, we're gonna be putting more and more cash on the balance sheet. We've talked here as a, a management committee, in the importance of having low debt, gross debt, as well as net debt. I mean, it's our goal to, to really drive net debt lower over, you know, over the, the medium term and short term as well. Yeah, I would say we'll continue to, you know, relatively put cash on the balance sheet and continue to pay off debt where we can. Yeah, our goal is to, to keep net debt low, and, you know, we kind of set that target about 0.5 times, and I would say that's kind of our, our bogey. Thank you. Your next question comes from the line of Derrick Whitfield of Stifel. Please go ahead. Thanks. Good morning, all. Congrats on a strong print. Thank you. Taking 15,000 foot laterals perhaps one step further, there's been a notable uptick in industry commentary this quarter on E&Ps achieving positive results on wells with laterals in the 15,000-20,000 foot range. With your improved outlook on 15,000 foot laterals, A, do you have a sense on how many locations you have in inventory that could support 20,000 foot laterals? B, are there any technical limitations or concerns you have with drilling 20,000 foot laterals? Yeah, it's I think it's a great question, and so I, I don't know the exact count on 20,000. Obviously, it's acreage specific in terms of what. How many wells of our 1,000+ could be 20,000? You know, what I'd probably say is we've drilled, you know, the longest ones, we've drilled just slightly over 18,000 foot, noted in our commentary. You know, I think as we get out there longer and longer, there's, you know, there comes a little bit more risk with that. You know, we're very comfortable with the 15,000-18,000 range. I know, you know, other peers have done 20,000 foot laterals and successfully, so it's not the technology, just like when we started and got to 12,500 and thought that was the, the limit, that the technology and equipment and tools get better and better. To the extent we can do longer laterals, it's more capital efficient. We think it's, you know, the right way to go. If we can get the right drawdown, then it improves those IRRs in return. We're gonna continue to, to test it, but, you know, so far what we've done is, you know, 18,000 feet with, you know, very successfully. Hopefully, we can continue to extend that over time. Great. As my follow-up, with your gas marketing strategy that you've outlined on page 12, how are you thinking about Pioneer's role in LNG over time and desire to be more connected with international gas prices? Yeah, I know. something we've been thinking about, you know, a lot and, you know, we've obviously, on a gross basis, are probably 1.3 Bcf a day of gas. and so just from a diversification standpoint, we are looking at the LNG markets and the new LNG facilities coming on and, and looking at, you know, what the economics are of being able to diversify a portion of our gas to, you know, European or Asian markets and link them to a TTF or JKM price. and so definitely something we're evaluating and looking at. You know, it won't be for a, you know, call it 10%-20% of our gas that we may, you know, over time add to that. You know, obviously, the facility's got to get built, so it's still a few years out, but definitely something that we're interested in and looking at longer term and think, you know, makes sense from a diversification standpoint to pricing markets. Thank you. Your next question comes from the line of Doug Leggate of Bank of America. Please go ahead. Thanks. Good morning, guys. Thanks for getting me on. I want to go back to productivity again, if you don't mind, but ask the question a little differently maybe. When you look at the chart of how the cumulative productivity is improving, it looks like it's more of a kind of a later stage recovery. I guess, I'm figuring you haven't got a lot of those long laterals on yet. My question is: What's the proportion of activity currently that's long lateral, and how would you expect that to evolve? Obviously, that's gonna play into how this productivity improvement feeds through to production. Yeah, maybe a couple comments, Doug. One, I think people may be reading too much into the graph because there's really... The wells are, it's just a forecast of, you know, our, our technical team forecasting those wells and, and as they would, you know, a 10,000 foot well. But in terms of our total program, I mean, we've got, you know, 100, you know, plus long laterals that we're planning on putting on production this year, and that's out of, you know, a total of, you know, roughly 500 wells. You know, call it 20% of our activity is long laterals in 2023. Hopefully that helps. Yeah, how, how do you expect that to evolve? Will it become a bigger proportion going forward, or is that a good run rate? No, I, I think it per one of the earlier questions, I think it will, you know, move slightly higher. We'll have to kind of see as we fit them in and make sure that from, you know, just all the logistics that go with it. You know, obviously, with, with a 35% increase in IRRs, you know, the more we can pull those forward, the better it is, and the less wells we have to drill on an annual basis to get that same, you know, production growth. It's, it's always a, a balance, but, you know, the intent is to, you know, probably drill a few more than 100 in, in 2024 and beyond. Thank you. Your next question comes from the line of Roger Read of Wells Fargo. Please go ahead. Yeah, thank you. Good morning. Not gonna hammer you anymore on, on, well productivity. I think that's been hit, but I did wanna come back to the base dividend growth outlook. You mentioned dividend grows with production, but I was curious if you're buying back shares as well, should we think of it as production adjusted per share count as well? Then the other part of that question is, how do you incorporate maintaining a premium yield, or does that actually matter to you, premium yield relative to the S&P 500? Good, good, good questions, Roger, and good morning. I would say, look, the base dividend, as I was talking about in terms of growing commensurate with production growth, is on an absolute basis. You're right, and that's a great way to look at it. As you buy back shares on a per share basis, it actually, you know, will prove beneficial and better for those that are holding the equity. I think that's a good way to think about it as well. As you think about the yield relative to the S&P 500, I mean, for us, it's nice, and it's a goal to be above that yield for certain. As we've talked about before, we really wanna sensitize the ability to pay that dividend. We view the dividend as being sacrosanct, as a commitment to our investor base. It's one that we can, one that we ensure that we can protect at all, you know, at lower oil prices. That's important to us as well. Now, as we grow the production base, that provides us a greater cash flow base to support that yield going forward, and support the increase of the dividend in absolute terms growing forward as well. That's kind of how we view it here. Again, it's something that we are very focused on, and it's very important to us, and it's very important to our shareholder base as well. We'll continue to grow that base dividend as we have historically, but more commensurate with production growth on a go-forward basis. Understood. Thank you. Your next question comes from the line of Paul Cheng of Scotiabank. Please go ahead. Thank you. Good morning. Rich, two questions, please. One of your major competitor has been testing out, and it seems they have success, has been successful in improving the recovery rate. From your standpoint, wondering that if Pioneer have tried that or whether that you think based on today's technology and pricing, the this type of activity could be support economically? That's the first question. Second question is that if we look at your oil cuts in 2019, it's about 61%-62%. In the first half, down to about 52%-53%. Just want to know whether that this is naturally, because natural gas decline at a slower pace than oil. As a result, it naturally that creep like this, or that is because you are moving into a more gassy portion of your portfolio. If that's the case, what's the trend line you expect over the next, say, one or two years? Thank you. Thanks, Paul. Maybe I'll take the first one. You know, just on the technology standpoint, you know, given our size and scale in the basin and how many wells we're completing per year, I mean, we understand or, or see most of what's happening in the basin from a technology standpoint. Our teams are working on technology to improve recoveries, you know, day in and day out, and doing an excellent job at it. You know, so we're not aware of any, you know, significant changes that, you know, are out there from any of our peers in terms of completion designs or things that are, you know, radically changing recoveries. What I'd tell you, the things that we're working on, as I mentioned in our comments, are things like our enhanced oil recovery to improve, you know, the recovery ability. We're only recovering call it 6%- 8% of the resource in the ground today, and so enhanced oil recovery hopefully will allow us to improve that. We still got more testing to be done, but it's technologies like that that we're working on to, you know, improve recoveries like I'm sure a number of our peers are. In terms of the oil cut, you know, I think you saw where we're kind of 52%-53%, you know, recently, you know, just as a normal function, that the oil cut comes down over time, particularly as we slowed our growth. That happens, you know, longer term, I think when you look at it and we look at the modeling, it really, you know, trends towards 50%, towards the, you know, later part of this decade. Yes, it gradually moves down slowly. Some of it's a function of growth, you know, overall, it's not moving dramatically going forward. We're focused on oil development, we're not getting gassier in any place other than just from the normal occurrence of how the wells perform. Hopefully that helps. Thank you. Your next question comes from the line of Leo Mariani of Roth MKM. Please go ahead. ... Just follow up briefly on that oil cut, you know, sort of comment here. Obviously, you know, very strong beats, you know, on production this quarter, but, you know, a little bit kinda less so on oil. Oil is sort of at the high end. I mean, you went from 53% oil cut first quarter to 52%, you know, this quarter. You don't wanna make too much about one quarter, but maybe there was some just additional gas recovery. You talked about focusing on, on oil development, you know, going forward and, and not necessarily gas here. You know, is, is there anything to kind of the new program where, where perhaps, as you've looked to sort of high grade a little bit, just the zones you focused on are a little bit more gassy? Just trying to get some of the local color on the recent change here. Yeah, no, appreciate the follow-up. I would say the, as it relates to specifically to the second quarter, I mean, we had the benefit of, you know, the, our processors having really strong plant yields, so that definitely, you know, helped during the quarter. Plus, we've, you know, continued to add field compression out there, and so lowering line pressure has helped. So all those things have benefited that, the gas production in the quarter. You know, obviously, we're gonna try and maximize production and continue to do those things that are efficient going forward. But like I said, I, I think it's, you know, a, a slow decline towards 50 to the back half of this decade, and it's really nothing to do with the, the wells that we're drilling or the change in the wells. It's just the, the normal process of what happens over time as we get a bigger and bigger base and, you know, the mix of oil and gas. Yeah, Leo, to, to be clear, following up on Rich, it's, it's not related to the new wells that we're popping. Those oil cuts are, are what they have been historically, so there's no change at all related to that in terms of zones or where we're drilling or, or anything of similar to, as Rich pointed out. Okay. No, that's helpful for sure. Then just to, to follow up on, on well productivity, certainly seems like you folks have, have credited a lot of the strong production performance that you're, you've seen already in 2023, and you're expecting more than that, you know, in the second half to some of the changes made. You know, it strikes me that a lot of these changes weren't implemented until the kinda second half of 2022. Presumably, you know, they're just kinda starting to hit now in the last handful of months. Seems like as we work our way into the end of the year into next year, we should see an even larger, you know, just change in, in sort of productivity as the percentage of kind of new production, you know, really gets a lot bigger over the next couple of years. It seems like if the trend continues, you guys will continue to be able to sort of improve your capital efficiency each year for the next couple of years and sort of, you know, do more with less. It seems like we're just getting started on the program here. Am I thinking about that the right way? Yeah, Leo, I'd, you know, say that, you know, we started probably earlier than there in terms of moving, and we only made some, you know, what I'd call minor changes to the, the program from full stack. So we've built that into our production guidance ranges and our, and our capital forecast. You know, clearly, that, you know. Everything you laid out is the goal and what the teams are working on, but, you know, we would think we've, you know, baked that into our guidance. I just, I don't want to not thank people that, we, we haven't baked in because we have. Thank you. This concludes the question and answer portion of today's call. I will now turn the call over to Rich Dealy for closing remarks. I really appreciate everybody joining the call today. Thank you all for your, your time. I hope you guys enjoy the rest of your summer, and look forward to seeing you in, you know, upcoming conferences as we get into the early fall. Everybody have a great rest of your week. Thank you. Thank you, and this concludes today's call. You may now disconnect.