Pioneer Natural Resources Company (NYSE:PXD) Q2 2023 Earnings Call Transcript

Pioneer Natural Resources Company (NYSE:PXD) Q2 2023 Earnings Call Transcript August 2, 2023

Operator: 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 @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 web page and 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 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 2 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.

Scott Sheffield: Thank you, Jay. 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, has been suppressed by SBR releases, recessionary fairs and weak economic data from China. The recent upward move in oil prices reflects the expectation for a tightening supply-demand fundamentals in the second half of this year. The major contributors to this include the Fed success in managing inflationary pressures and preventing a recession, likely resulting in a soft landing for the U.S. economy.

China actually taken measures to bolster its economy through stimulus programs, limited U.S. oil shale supply. The end of substantial U.S. SBR releases which has resulted in a 40-year low inventories. This outlook is further supported by Saudi Arabia’s production cuts and ABS’ 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 1 toward the end of ’23. I see these factors leading to demand outpacing supply, resulting in global inventory draws during the second half of ’23. The expected demand increase, combined with the underinvestment by industry over the last several years, are both supportive for oil pricing in the $80 to $100 range for the remainder of ’23 and through ’24 on.

Now turning to Pioneer’s performance, we delivered excellent second quarter results linked 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 highlighting 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.

Rich Dealy: 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 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 and full year outlook, we continue to return significant capital to shareholders with 75% of our free cash flow being returned through 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 continued efforts can be found in our recently published 2023 sustainability report. Turning to Slide 4. Team’s continued focus on execution resulted in a 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 5. 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 6. 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. And which are being driven by longer laterals, same 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 to 25 rigs due to our intentional activity reductions.

As a result, the protected number of wells placed on production during 2023 now ranges from 490 to 520. Turning to Slide 7. Looking at the chart on the left. As expected, our 2023 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 breakeven 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 breakevens.

This deep inventory is highly productive — of highly productive wells enables our best-in-class development for decades to come. Turning to Slide 8. As part of our low breakeven inventory, Pioneer has an extensive inventory of extended lateral length wells. This slide highlights the benefits of long lateral length development both lower cost 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 resulted 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. And as we move — pardon me, and we expect more than 100 of these wells we placed on production in 2023. And 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 9. 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 second localized sand mine during the second quarter. These localized sand lines reduced 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 fleet 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.

Neal Shah: Thank you, Rich, and good morning. Turning to Slide 10. Pioneer continues to return significant capital to shareholders through dividends and opportunistic share repurchases and 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 team’s focused on driving low peer-leading operating cost 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 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 multiyear 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 5-year cumulative free cash flow of $27 billion, assuming an $80 WTI flat oil price or approximately 50% of our enterprise value. Even at $60 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 are 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.

And with that, I will hand things back to Rich.

Rich Dealy: 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 Hutt Wind 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 element of Pioneer’s strategy, which supports our commitment to creating value to shareholders.

So with that, Jay, we’re going to open up the call or happy to open the call for questions.

Q&A Session

Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions] Your first from the line of John Freeman of Raymond James. Please go ahead.

John Freeman: It’s really nice in the well productivity trends continue. And I guess I was just thinking in the past when you all talked about the kind of that long-term 0% to 5% growth range, and you’ll talk about kind of adding one or two rigs a year. Just based on what you’re seeing from productivity, capital efficiency kind of improvement, is that sort of changed how you all view kind of the necessary rig add to accomplish that? Or I guess, said differently, is that second half ’23 activity run rate, is that something close to what we should assume as a base case for 24?

Rich Dealy: Yes, John, it’s probably a little to talk about ’24 just from a total standpoint, but I would say as we look at it, going forward, we see production in that upper half of our 0% to 5% range is where we target production for 2024 based on a day. In general, as we’ve talked about, as you outlined, it takes one to two rigs to grow at that level. But as you point out, we’ve had significant growth in productivity in 2023. And so that should make 202 are very capital efficient. And so to me, it probably means that we’re at the lower end of that one to two rigs or maybe even potentially flat. So more to tell, but the teams are doing a great job on execution and driving efficiencies, which really allows things to do more with less rigs and less frac fleets, great job by the team.

John Freeman: And then my second question on the $125 million CapEx reduction at the midpoint. Is it possible to break that down between how much is just due to the reduction in activity versus maybe other cost savings that you weren’t originally expecting?

Rich Dealy: Yes. Most of it is really driven by activity, as you saw by the reduced average one rig down and then 10 less pops. So that’s the biggest contribution. Clearly, we are seeing some deflation mainly on steel projects or casing and tubular goods, some on fuel and chemicals that are helping. We’ve heard commentary about rig rates and frac fleet rates coming down from what we’ve seen, those are mainly on spot rates and they’re on what I’d call less efficient rigs and Tier 2 equipment on the frac side. And 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. And so I just think it’s just test and our teams. I don’t really see a lot of change in the back half of this year, maybe it’s impact 2024. But today, we’re still in a favored price on pricing other than steel and getting the benefits of steel and fuel.

Operator: Thank you. Your next question comes from the line of Neil Mehta of Goldman Sachs. Please go ahead.

Neil Mehta: [indiscernible] John’s comments, good to see the productivity improvements coming through here. So Rich, it’s been a couple of months since then CEO announcement was made. Would 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?

Rich Dealy: Yes. Thanks, Neil. I think you’re seeing it demonstrated in the quarter. I mean our focus is on execution and delivering what we set out to at the beginning of the year. And I think you’re seeing the great work of our 2,000 employees delivering the results with the improved well productivity driving down capital costs and increasing efficiencies. And so, that’s really how we’re measuring ourselves internally is delivering what we set out to at the beginning of the year. And I think this quarter is a good example of we hope to do. And it’s really just 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.

Neil Mehta: And then the follow-up is just return of capital, your 75% of free cash flow went back to shareholders and was balanced between the base dividend share repurchases. Maybe you can 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%?

Neal Shah: Neil, it’s Neal as well. Look, you’re precisely right. The return of capital framework really provides us a flexibility to allocate capital between variable dividends and opportunistic share repurchases. Really based on where we see the best value for shareholders. Also considering the diverse shareholder base that we have, which includes income-oriented investors as well, really kind of employ a balanced approach to assessing the variable dividend versus opportunistic share repurchases. So, I think going forward, we anticipate a component of each on a quarterly basis, but it will shift quarter-to-quarter really based on where we see value, really stepping in the market and being opportunistic as you were this past quarter.

75% in terms of return of capital to shareholders, that’s kind of — as we talk about it based on the framework kind of a firm number. But we have said that will utilize the balance sheet if we see the opportunity and the chance to really step it in the market if the stock drops precipitously. So, I think that’s always a definite possibility.

Operator: Thank you. Your next question comes from the line of Arun Jayaram of JPMorgan. Please go ahead.

Arun Jayaram: 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 reflected in your results in the first half of the year. And how much do you see is still on the come? And maybe you could give us a sense of your secret sauce or what you’re doing to kind of bolster your well productivity at this point?

Rich Dealy: Sure, Arun. Great question. I’d say it’s what we’ve talked about in the past is we are really focused on developing our full stack development across our inventory thing. And so, that you’ve seen that move. And then you’ve also seen as you move to the 15,000-foot laterals, which is something unique to our acreage position that we have a deep inventory of those. And so I think it’s the combination of those things that are really driving the productivity results as we expected coming into the year. It’s probably happened a little earlier in the year than we anticipated, but it’s still something that the well results are fantastic. The team has done a great job on execution and something that I think by the updated guidance, you can see will continue into the second half of the year.

So that’s really — the plan is not anything fancy. It’s just developing our great acreage position with full stack development, which I think it maximizes recoveries and improves and is the optimized way to get the highest rate of return.

Arun Jayaram: Great. And my follow-up, Rich, you’re taking down your 2023 CapEx by about 3% below expectations by 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 one to two rigs to kind of deliver that 0% to 5% growth?

Rich Dealy: Yes. I think 2024, as I mentioned on John’s question, is going to be really highly capital efficient. I just think when you’re — the growth that we’re showing in 2023, when you think about growing in the upper half of our 0% to 5% next year, you basically got a good jump start in it, just with what’s happened in 2023. So we see ’24 as very capital efficient. Hopefully, it’s even better with some deflationary pressure on the cost side of things. It’s too early for me to kind of predict what that’s going to look like just given where oil prices are and what — where oil prices may be headed the back half of this year. So, we’ll have to wait and see, but it’s something our supply chain team is working on day in and day out to see how we can make sure we have favorable pricing going into 2024. But all said, I think you’re right that it’s going to be a very capital-efficient program in ’24 based on what we know today.

Operator: Thank you. Your next question comes from the line of Scott Gruber of Citigroup. Please go ahead.

Scott Gruber: You guys have been adding same frac crews, new frac crews this year and your completion efficiency is really impressive. But is it still getting better? And are the gains sufficient such that you can possibly drop frac crew on a normalized basis.

Rich Dealy: Scott, it’s something that the teams are working on every day to drive that efficiency. I think it will be harder for us to add another simul-frac just because of the movement of logistics, mainly is the biggest thing. But it’s not to say the teams aren’t looking at it. But we have gotten more efficient. The teams are really having less non-productive time more efficient on location. And so that’s — the ideal goal is to do that. So, ultimately, that’s the focus of the teams is to continue to improve that efficiency longer term. There’s other things like on the localized sand mine would be another thing that we’re working on. We’ve got two of those. We’re looking at a third one in 2024 that would reduce those well costs that it could be applied to in ’24. So, there’s things like that. The teams are continuing to work on that hopefully will allow us to either further improve well costs in ’24.

Scott Gruber: Got it. And just on another initiative to reduce well costs and improve capital efficiency, the 15,000-foot program. I think it consisted of around 100 wells this year. As you start to plan for next year, how will that figure change? Is it going to go up meaningfully?

Rich Dealy: I think the goal is for it to go up. They’re still planning on know what that looks like, how meaningfully it goes up is really just balancing where we’re at in the field and logistics to go with it in timing. But given the higher rates of return, obviously, more of those we can move into the front of the program, the better. And then really the less wells we drill and less activity we have as well to get the same production targets. So definitely a great advantage to the Company and something that we’re working on and so modestly increase in ’24, what I’d say, today, but it’s still work in progress.

Operator: Thank you. Your next question comes from the line of Matt Portillo of TPH. Please go ahead.

Matt Portillo: Just to dig in a little bit. Obviously, the well improvement year-to-date has been fantastic. I was curious, as we look at 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 dynamics for the 2023 program, the spacing design changes you guys have implemented or any other factors that you could point to that is really driving that productivity gain for the Spraberry?

Rich Dealy: Yes, Matt, I don’t have the specifics on that zone, but I’d say just more broader picture, really the full stack development we’re seeing across all zones. I think when you look in the state data that the improvement by developing out a full stack is just a better way to maximize recoveries and returns. And so that’s really been our focus. And in terms of the 15,000-foot ladders we’re doing those across all zones as well. So, I just think it’s I don’t know the specifics on the lower Spraberry, in particular. But overall, the well performance has been fantastic as you can see from the data.

Matt Portillo: Perfect. And then just as a follow-up, maybe for Scott. I know you spent 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 in 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.

Scott Sheffield: Yes. I think you’re starting to see it in the U.S. Lower 48 production to with the recent EIA data. So it’s definitely slowing. People are definitely going to run out of inventory over the next several years. Most people, except for a few of us, like Pioneer, another two or three others in the Permian Basin, which will lead to — it should lead to extreme consolidation. So, that will continue and it’s all based on inventory. And there’s private equity is running out of opportunities to divest.

Operator: Thank you. Your next question comes from the line of David Deckelbaum of Cowen. Please go ahead.

David Deckelbaum: Thanks Rich, Neal and the Scott. I appreciate the time this morning. A lot has been covered already, but I was curious, just going back to a slide where you talk about as well productivity that you’re estimating this year and the gains. And you do see, I guess, some greater outperformance as you get into a longer life for the well beyond two years. I guess I’m curious. One, what have you seen to date, I guess, 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 this percentage of outperformance on a per foot basis?

Rich Dealy: David, great question. That graph really includes actuals to-date and then the forecast over that 24-month period of what we anticipate. I’d say the real benefit is as we did these artificial lift refinements and really customize artificial lift by zone and by area, but that’s really paid dividends and just drawing down the wells quicker, allowing to bring that productivity forward. And so, we’ve just seen the benefits of that, and you can see it in the state data, the higher productivity from those wells by just really managing the artificial lifts and customizing it where appropriate.

David Deckelbaum: I appreciate that. And 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? And is that something that should tick up with sort of completion intensity or lateral length intensity over time? Or is that something that’s going to be trending in a more positive direction in ’24 and ’25?

Rich Dealy: Yes. I think longer term, it’s going to — I mean, ’24, ’25 is probably not too different than what it was in 2023. But longer term, as more of the basin gets developed we can use existing facilities and infrastructure and take advantage of that, so that capital should moderate over time as we’ve talked about. The 15,000-foot laterals in terms of the facilities that go with those, yes, they’ve got a little more volume to handle, but the economics are so strong, as you can see that it’s very worthwhile and in and around areas where we’re going to add additional wells in time, too. So overall, like we talked about, it’s all pointing to more capital-efficient operations longer term.

Operator: Thank you. Your next question comes from the line of Scott Hanold of RBC Capital Markets. Please go ahead.

Scott Hanold: Just another question on the productivity improvement and 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 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?

Rich Dealy: Yes, great question. And really what we’re seeing with the artificial lift and modifications is that they’re maybe not quite, but almost essentially basically better like you’d expect from a 10,000-foot lateral on a productivity per foot. So sometimes we’re limited by the fluid, we can move until there’s a short where they’re flatter because of these bigger ESPs, high-pressure gas lift, we’re moving more fluid volumes and therefore, drawing them down quicker and getting basically on that, what I’d say, a proportionate curve to be a 10,000-foot lateral.

Scott Hanold: Yes. No, that’s helpful. And then going back to shareholder returns and maybe this one, Neal. How do you think about the fixed dividend? Obviously, you gave some pretty good color on that you’ve got a balanced investor base like income and obviously some like buybacks. But what is your goal on that fixed dividend moving forward? Like where do you want it to be? How competitive in the growth kind of pace of it?

Neal Shah: Yes, that’s a great question, Scott. You’ve seen our commitment to a strong and growing base dividend. We’ve increased it consistently over the previous six years. And recently, just last previous quarter, we increased it by an additional 14%. Our current base dividend, if you think about the total yield package, we’re at 3.3%, which outpaced the S&P 500 1.5%. So, we believe the base dividend is extremely important and an avenue of return to our shareholders. So going forward, I would expect that base dividend increase roughly commence with our production growth. But again, it’s a very important return avenue for us in terms of getting that capital and cash back into shareholders’ pockets.

Operator: Thank you. Your next question comes from the line of Charles Meade of Johnson Rice. Please go ahead.

Charles Meade: Rich, Scott and Neal and to the rest of the PXD team there. Rich, I just have — just one question for me. It’s about the reduction of the rig and the average rig count for the year. So you reduced the range by one. Am I right to think that since that’s happening for back half for the back half of the year that you’re actually reducing the rig count in the back half of the year by two. And maybe tell me if that’s the right way to think about it and give a little more color if those rigs are already down or this is a — it’s going to happen in the next couple of months or just more color there if you could.

Rich Dealy: Yes, Charles, good question, and you’re spot on. I mean the average rig count is for the year. So we have rig count ebbs and flows just with our activity level. So it’s not always stagnant. We have some that roll off and bring ones on. But directionally, you’re right that we have dropped multiple rigs at this point. really reflecting that average rig count me on. So you’re exactly right.

Operator: Thank you. Your next question comes from the line of Neal Dingmann of Truth Securities. Please go ahead.

Neal Dingmann: 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 how could we — how would you all have us consider about well cost maybe through the end of the year, in particular in ’24?

Rich Dealy: Yes, still early for ’24. So I hate to get there, but obviously, with moving the capital down our well costs are — you can take that $125 million and divide it out and that’s what we’re seeing in terms of decrease in well cost going forward because of just the improved program. Like I said, the key kind of deflationary things that are out there, really OCTG steel and fuel and chemicals that we’re seeing. We’re seeing things on a few other things, but that’s where the majority of the savings is coming from and then just reduced activity like we talked about. So overall, trending the right way and hope to see those continue and everybody is working on that.

Neal Dingmann: Yes, it certainly seems like it rich. And then secondly, maybe for Neal, just on the balance sheet. and shareholder return. You all done a great job on the shareholder term that’s been talked about. It looks like net debt went up a little bit. So I’m just wondering on a go forward, how do you balance all those things, I guess, maybe you’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?

Neal Shah: Yes, that’s a good question. I mean in a higher commodity price environment, we’re going to be putting more and more cash on the balance sheet. We’ve talked here as a management committee in the importance of having low debt — gross debt as well as net debt. So, I mean it’s our goal to really drive net debt lower over the medium term and short term as well. So yes, I would say we’ll continue to relatively put cash on the balance sheet and continue to pay off debt where we can. But our goal is to keep net debt low and we kind of set that target about 0.5x. And I would say that’s kind of our bogey.

Operator: Thank you. Your next question comes from the line of Derrick Whitfield of Stifel. Please go ahead.

Derrick Whitfield: Congrats on a strong front.

Rich Dealy: Thank you.

Derrick Whitfield: Taking 15,000 foot laterals, perhaps one step further. There’s been a notable uptick in the mystery commentary this quarter on E&Ps achieving positive results on wells with laterals in the 15,000 to 20,000 foot range. With your improved outlook on 15,000 laterals, a, do you have a sense of how many locations you have an inventory that could support 20,000 foot laterals, and b, are there any technical limitations or concerns you have with drilling 20,000 laterals?

Rich Dealy: Yes. I think it’s a great question. And so 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-plus could be 20,000. What I’d probably say is, we’ve drilled the longest ones we drilled just slightly over 18,000 foot I noted in our commentary. And think as we get out there longer and larger there becomes a little bit more risk with that. We’re very comfortable with the 15,000 to 18,000 range. But I 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 12.5 and thought that was the limit that the technology and equipment and tools get better and better. So to the extent we can do longer laterals, it’s more capital efficient.

We think it’s the right way to go. And if we can get the right drawdown, then it improves those IRRs and returns. So we’re going to continue to test it. But so far, what we’ve done is 18,000 feet with very successfully. So hopefully, we can continue to extend that over time.

Derrick Whitfield: Great. And 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?

Rich Dealy: Yes. No, something we’ve been thinking about a lot. And we 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 looking at what the economics are of being able to diversify a portion of our gas to European or Asian markets and link them to a TTF or JKM price. And so definitely something we’re evaluating and looking at it won’t be for a, call it, 10% to 20% of our gas that we may, over time, add to that. Obviously, the facility has got to get built. So, it’s still few years out, but definitely something that we’re interested in and looking at longer term and think makes sense from a diversification standpoint to pricing markets.

Operator: Thank you. Your next question comes from the line of Doug Leggate of Bank of America. Please go ahead.

Douglas Leggate: 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. And I guess I’m figuring you haven’t got a lot of those long laterals on yet. So my question is, what’s the proportion of activity currently that’s long lateral? And how would you expect that to evolve, because obviously, that’s kind of play into how this productivity improvement feeds through to production?

Rich Dealy: Yes. Maybe a couple of comments, Doug. One, I think you may be reading too much into the graph because there’s really — the wells are — it’s just the forecast of our technical team forecasting those wells and as they would a 10,000-foot well. But in terms of our total program, I mean, we’ve got 100-plus long laterals that we’re planning on putting on location production this year, and that’s out of a total of roughly 500 wells. So call it, 20% of our activity is long laterals in 2023. So hopefully, that helps.

Douglas Leggate: How do you expect that to evolve? Will it become a bigger proportion going forward? Or is that a good run rate?

Rich Dealy: No, I think it’s prone of the earlier questions. I think it will move slightly higher. We’ll have to kind of see as we fit them in and make sure that from just all the logistics that go with it. But obviously with 35% increase in IRRs 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 production growth. So it’s always a balance, but the intent is to probably drill a few more than 100 in 2024 and beyond.

Operator: Thank you. Your next question comes from the line of Roger Read of Wells Fargo. Please go ahead.

Roger Read: Yes. Not going to hammer you anymore on well productivity. I think that’s been hit. But I did want to 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 for share count as well? And 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?

Neal Shah: Good questions, Roger, and I would say, look, the base dividend, as I was talking about in terms of growing commensurate production growth is on an absolute basis. But you’re right, and that’s a great way to look at it, as you buy back shares on a per share basis that actually will prove beneficiary better for those that are holding equity. So, 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 it’s — for us, it’s nice and it’s a goal to be above that yield for certain. But as we’ve talked about before, we really want to sensitize the ability to pay that dividend. We view the dividend as being sacrosanct as a commitment to our investor base. So it’s one that we can — one that we ensure that we can in fact at all at lower oil prices.

So 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 going forward as well. So, that’s kind of how we view it here. But 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. So, we’ll continue to grow that base dividend as we have historically, but more commensurate with production growth on a go-forward basis.

Operator: Thank you. Your next question comes from the line of Paul Cheng of Scotiabank. Please go ahead.

Paul Cheng: With two questions, please. One of your major competitors has been testing now and it seems like you have success has been successful in improving the recovery rate. From your standpoint, wondering that your, Pioneer have tried that or whether that you think based on today’s technology and pricing, this kind of activity could be support economically? That’s the first question. Second question is that if we look at your oil cuts in 2019 is about 61%, 62% in the first half down to about 52%, 53%. Just want to know whether that is naturally because natural gas become at a slower pace than oil, so as a result in naturally that creep might this or that is because you are moving into a more gassy portion of your portfolio? And if that’s the case, what’s the trend line you expect over the next, say, one or two years?

Rich Dealy: Thanks, Paul. Maybe I’ll take the first one. Just on the technology standpoint, given our size and scale in the basin and how many wells we’re completing per year. We’re — we understand or see most of what’s happening in the basin from a technology standpoint. Our teams are working on technology to improve recoveries day in and day out and do an excellent job at it. So we’re not aware of any significant changes that are out there from any of our peers in terms of completion designs are things that are radically changing recoveries. And 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 the recovery ability we’re only recovering, call it, 6% to 8% of the resource in the ground today.

And so enhanced oil recovery, hopefully will allow us to improve that. And we still got more testing to be done. But it’s technologies like that, that we’re working on to improved recoveries like I’m sure a number of our peers are. In terms of the oil cut, I think you saw where we’re at kind of 52%, 53% recently, just as a normal function that the oil cut comes down over time, particularly as we slowed our growth, that happens. But longer term, I think when you look at it and we look at the modeling, really trends towards 50% towards the later part of this decade. And so it’s — yes, it gradually moved down slowly. Some of it is a function of growth. But overall, it’s not moving dramatically going forward. And we’re not — we’re focused on oil development.

And so we’re not getting gassier in any place other than just from the normal occurrence of how the wells perform. So hopefully, that helps.

Operator: Thank you. Your next question comes from the line of Leo Mariani of ROTH MKM. Please go ahead.

Leo Mariani: To just follow up briefly on that oil cut sort of comment here, so obviously, very strong beats on production this quarter, but a little bit kind of less so on oil sort of at the high end. I mean, you went from 53% oil cut, first quarter this quarter. So, I don’t want to make too much about one quarter, but maybe there was some just additional gas recovery. You talked about focusing on oil development going forward and not necessarily gas here, but is there anything to kind of the new program were perhaps as you look 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?

Rich Dealy: Yes. No. And I appreciate the follow up. And I would say as it relates to specifically to the second quarter. I mean we had the benefit of our processors having really strong plant yields. So that definitely helped during the quarter, plus we continue to add field compression out there and so lowering line pressure has helped. And so all those things have benefited that the gas production in the quarter. And obviously, we’re going to try and maximize production and continue to do those things that are efficient going forward. But like I said, I think it’s a slow decline towards 50 to the back half of this decade and it’s really nothing to do with the wells that we’re drilling or the change in the wells. It’s just the normal process of what happens over time as we get a bigger and bigger base in the mix of oil and gas.

Neal Shah: And Leo, to be clear, following up, Rich, it’s not related to the new wells that we’re popping. Those oil cuts 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 anything similar, as Rich pointed out.

Leo Mariani: Okay. No, that’s helpful for sure. And then just to follow up on well productivity. It certainly seems like you folks have credited a lot of the strong production performance that you’ve seen already in ’23 and you’re expecting more than that in the second half to some of the changes made. But it strikes me that a lot of these changes weren’t implemented until the kind of second half of 2022. So presumably, they’re just kind of starting to hit now in the last handful of months. So seems like as we work our way into the end of the year into next year, we should see an even larger just change in sort of productivity as the percentage of kind of new production really gets a lot bigger over the next couple of years.

So 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 do more with less. It seems like we’re just getting started on the program here. Am I thinking about that the right way?

Rich Dealy: Yes, Leo, I say that we started probably earlier there in terms of moving, and we only made some, what I’d call, minor changes to the program from full stack. And so we’ve built that into our production guidance ranges and our capital forecast. Clearly, that everything you laid out as the goal and what the teams are working on, but we would think we’ve baked that into our guidance. So, I just — I don’t want to not think people — we haven’t baked in because we have.

Operator: This concludes the question-and-answer portion of today’s call. I will now turn the call over to Rich Dealy for closing remarks.

Rich Dealy: I really appreciate everybody joining the call today. Thank you all for your time. I hope you guys enjoy the rest of your summer and look forward to seeing you in upcoming conferences as we get into the early fall. So everybody, have a great rest of your week. Thank you.

Operator: Thank you. And this concludes today’s call. You may now disconnect.