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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Welcome to Pioneer Natural Resources Third Quarter Conference Call. Joining us today will be Scott Sheffield, Chief Executive Officer; Rich Dealy, President and Chief Operating Officer; and Neal Shah, Senior Vice President and Chief Financial Officer.
Pioneer has prepared presentation slides to supplement comments made today. These slides are available on the Internet at www.pxd.com. Navigate to the Investors tab found at the top of the web page and then select investor presentations. Today's call is being recorded. A replay of the call will be archived on www.pxd.com through November 22, 2022.
The company's comments today will include forward-looking statements made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from forward-looking statements. These risks and uncertainties are described in Pioneer's news release, on Page 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 Senior Vice President and Chief Financial Officer, Neal Shah. Please go ahead, sir.
Thank you, Melinda. Good morning, everyone, and thank you for joining us for Pioneer's third quarter earnings call.
Today, we will highlight Pioneer's excellent third quarter financial and operating results and peer-leading return of capital strategy. Importantly, we will discuss the increased return thresholds we are instituting beginning with our 2023 program, as well as the strong benefit we are seeing through our long lateral development. We are also excited to highlight our participation in 2 renewable energy projects that will help reduce our emissions profile and further strengthen our leading ESG strategy. We will then open up the call for questions.
With that, I will turn it over to Scott.
Thank you, Neal. Good morning.
Starting on Slide 3. Pioneer delivered strong results, generating over $1.7 billion in free cash flow during the third quarter, contributing to the return of $1.9 billion back to the shareholders. The majority of this capital is being returned through our base plus variable dividend of $5.71 per share, which will be paid in mid-December.
Additionally, we continue to execute on opportunistic share repurchases, with $500 million of shares retired in the third quarter at an average price of $218, representing approximately 2.3 million shares. This strong return of capital through both dividends and share repurchases represents approximately 108% of our third quarter free cash flow.
When including all repurchased to date and dividends to be paid in 2022, we will return approximately $7.5 billion to shareholders this year. This robust return clearly demonstrates our commitment to our investment framework that is supported by our significant free cash flow generation. We are also pleased to announce that we're participating in 140-megawatt wind generation project with NextEra. This project utilizes Pioneer's own service acreage to generate renewable energy that we will utilize in our operation.
Going to Slide 4, on our third quarter results. Pioneer's strong execution continued during the third quarter, with [ both ] oil and total production in the upper half of our guidance range, driving substantial free cash flow generation of greater than $1.7 billion. Our leverage profile remains top tier, which we forecast to be less than 0.3x net debt to EBITDA at year-end.
Going to Slide 5. Supplementing our best-in-class dividend payout, we continue to repurchase our shares opportunistically and have executed $1.5 billion since the fourth quarter of 2021 at an average share price of $219. This represents a reduction of total shares outstanding by approximately 3% at a strong discount to our current share price. Of the 500 million repurchased during the third quarter at an average price of $218 per share, 250 million of stock was repurchased in the month of July at an average share price of $213 through our 10b5 program. To date, we've utilized $1.25 billion of our current $4 billion authorization, leaving nearly $3 billion remaining under the program.
Going to Slide #6. Our core investment thesis remains unchanged, underpinned by low leverage, strong corporate returns and a low reinvestment rate. This delivers moderate oil production growth, but generates significant free cash flow. Majority of this free cash flow was returned to shareholders through our strong and growing base dividend and our peer-leading variable dividend, which represents up to 75% of post-base dividend free cash flow.
We strengthened this quarter's total return by leveraging our strong balance sheet to aggressively repurchase shares. In total, this resulted in returning $1.9 billion to shareholders, which equates to an annualized yield of greater than 12%.
Going to Slide #7, Pioneer's high-quality assets, low breakeven and moderate oil growth provides the ability to pay significant dividends from our peer-leading free cash flow through cycle. As seen on the graph, we're able to deliver a compelling base plus variable dividend with the yield far exceeding the S&P average at oil prices of $60. Conversely, shareholders have significant upside to sustain higher oil prices as well, with a greater than 10% dividend yield at oil prices higher than $100 WTI.
Going to Slide #8. Total dividends to be paid in 2022, resulting in a yield in excess of 10% at today's share price. This yield exceeds all peers and majors in the average yield of the S&P 500.
Going to Slide #9. When looking beyond our peer group to the broader market, Pioneer's dividend yield exceeds every S&P 500 sector. Our double-digit dividend yield demonstrates the cash flow generative power and underlying quality of Pioneer's assets and the strength of our peer-leading return of capital strategy.
I'll now turn it over to Rich.
Thanks, Scott, and good morning, everybody.
I'm going to start on Slide 10, where you can see that our full year 2022 production and capital guidance remains unchanged from our previous update in August.
Updating for actual results for the third quarter and forecasted strip prices for the fourth quarter, we are now estimating that we will generate over $12 billion in operating cash flow for the year and deliver more than $8 billion of free cash flow for the year. As you can see in the upper right, our average activity level remains unchanged, and we plan to run between 22 and 24 rigs and approximately 6 frac fleets, with 2 of those being simulfrac fleets for the remainder of the year.
Turning to Slide 11. As you would expect, we continually strive to be more efficient, improve return and implement the learnings into our development program. Consistent with this DNA inside the company, we have been not satisfied with the 2022 well performance and have made a significant step change to our well return thresholds going forward. This material threshold increase will substantially improve well productivity for 2023 and subsequent years. Implementing these more stringent threshold to result in the productivity of our future development programs surpassing the 2021 program levels, which are significantly higher than the 2022 levels and result in better capital efficiency and higher free cash flow per BOE.
Over the course of 2022, our development strategy has fully transitioned to a full stack approach, which includes drilling up to 6 highly productive zones. We have also significantly reduced our delayed developments and are taking advantage of our contiguous acreage position to drill extended 15,000-foot laterals that generate 20% higher returns than a 10,000-foot well. Given the quality and depth of our inventory, this higher threshold program is consistent and highly repeatable for many years past the 2023 to 2027 period highlighted on the graph on the right.
Turning to Slide 12. And as I mentioned on the previous slide, we are realizing improved returns and strong productivity from drilling 15,000-foot lateral wells. Developing these long laterals provide significant efficiency gains that reduce capital costs, resulting in an average drilling and completion savings of approximately 15% per lateral foot. The combination of these savings and the strong productivity drive increased returns with IRRs increasing by more than 20 percentage points when compared to 10,000-foot laterals.
Pioneer's extensive contiguous acreage position in the Midland Basin, which approaches nearly 1 million gross acres, supports our development of high-return 15,000-foot lateral wells. To date, we have identified more than 1,000 locations for long lateral development and expect to place more than 100 of those wells online in 2023, up from the 50 or so that we plan to put online in 2022.
Turning to Slide 13. As you can see on the left, Pioneer has the longest duration of high-quality inventory when compared to peers. This third-party data highlights Pioneer as a premier independent oil and gas company, with decades of high-quality inventory in the core of the Midland Basin.
Turning to Slide 14. This slide highlights the powerful combination of Pioneer's highest free cash flow per BOE amongst our peers, combined with having the longest duration of high-quality inventory in the U.S. unconventional space. This combination of robust free cash flow generation and decades of high-return inventory supports Pioneer's ability to return significant capital to shareholders over a long period of time and differentiates Pioneer from its peers.
I'll stop there and turn it over to Neal.
Thank you, Rich.
Turning to Slide 15. For multiple consecutive quarters, Pioneer has delivered the highest cash margin of our entire peer group. Our unhedged oil-weighted production underpins strong price realizations, which when netted against our low cash costs, drive these unmatched results. As we've discussed previously, our low cash costs are a function of a robust infrastructure, low coupon debt and top-tier G&A. This best-in-class margin, paired with our highly efficient operations, support the highest free cash flow per BOE produced.
Turning to the next slide. Pioneer continues to offer an attractive investment case for shareholders through the combination of leading corporate returns and an [ inexpensive ] valuation. Pioneer's projected ROCE continues to exceed all other sectors within the S&P 500, as well as the majors and the broader energy sector. Pairing our strong return profile with our discounted valuation, we believe results in an extremely compelling and durable investment opportunity for shareholders.
With that, I'll turn it back to Scott.
Thank you.
Going to Slide 17. We published our 2022 sustainability report earlier this year, which highlights Pioneer's focus and significant progress on our ESG initiatives. We believe that these actions demonstrate our commitment and focus on ESG and further strengthen Pioneer's position as a leader in the industry. Our updated sustainability report can be found on our website, and we expect to publish an updated climate risk report later this quarter.
Going to Slide 18. We're excited to announce our participation in a wind development project on Pioneer's owned service acreage, as well as the Concho Valley Solar project. Both renewable energy projects will supply power to both Pioneer's field operations in Targa and Pioneer's jointly owned Midland Basin gas processing system. This renewable energy and the renewable energy credits generated will reduce our Scope 2 emissions and contribute to our emission reduction goals.
The Concho Valley Solar project is currently operational and the [indiscernible] wind development, being built by NextEra, is expected to be operational in 2024. We are pleased to have NextEra as a partner, and they have unmatched experience in developing wind and solar resources. We continue to evaluate further wind and solar development on Pioneer's own service acreage in addition to these 2 initial projects.
On the final slide, on Slide 19, this is the summary of our key attributes that we have discussed today, which highlight our commitment to creating value for our shareholders.
We will now open the call for questions.
[Operator Instructions] And we'll go to our first caller, Neil Mehta with Goldman Sachs.
I just want to turn to Slide 11, and Rich, maybe you can expand on it a little bit more here. So as you think about the path for when you expect well productivity to inflect, are you saying '22 represents sort of the trough year and '23 get sequentially better? Or do we have to look out further in that 2023 to 2027 stack to see that inflection?
Yes, Neil, great question. Yes, it's really '22 will be the trough. I mean, we've started and made the change immediately. But as you know, there's a planning process and permitting process. So you will start to see those wells spud in the first quarter and see the results of the higher thresholds as we move through the course of 2023. So that's really the game plan going forward. I mean, basically, it means every well in the program we've got a higher bar and it's going to increase our program productivity, it's going to increase our annual capital efficiency and result in higher free cash flow generation from that program into '23.
And just to build on this because it's gotten so much investor focus here over the last couple of months. What is the confidence interval about the improvement that you expect in productivity? What is the biggest risk to achieving this shift?
Neil, just given that our -- having over 3,000 horizontal wells out there and having a big database of data, I think it's very low risk. We're really just reshuffling the portfolio and bringing forward higher return wells and deferring some of the wells that were great wells, but we can do -- we got higher thresholds that we can hit. And so we've just deferred those and reallocate the capital. But the reality is we have high confidence that we're going to achieve the results that we have laid out here.
And moving on to John Freeman of Raymond James.
When we look at the 2023 plan, I know that you all got the vast majority of what you all need sort of already secured. But when you just sort of think about the supply chain, just anything that you're seeing that sort of loosening versus what areas are still remaining pretty tight and you sort of try to nail down your plan for next year?
Yes, John, I think we've pretty well got most of it tied up in terms of from what we need from an activity level. I mean, just to give you a flavor of what '23 kind of is going to look like. Think about it as 24 to 26 rigs, probably 6 to 7 frac crews, and of which 3 of those will probably be [ e-fleets ] over the course of the year as those come in is really what we're looking at. As we look at '23, and that's going to put our -- it's still early and we're still working on, but growth in that mid-0% to 5% range is where I kind of say given where we're at today, so -- but I don't really see anything from -- hopefully, we'll see which is the biggest inflation [ like ] we've had, this year has been steel and casing prices. Having talked to a number of suppliers, it sounds like that's flattening a bit, but we'll see if that comes to fruition or not.
But otherwise, everything else, I think it seems like we're not at the same level of inflation. I think we've talked about before that we're still seeing '23 relative to our program in '22, kind of that 10%-type inflation level. It could be slightly higher, but that's generally where we're seeing it. Hopefully that helps.
Absolutely. And then you mentioned the 3 [ e-frac fleets ] that you got that are going to be delivered next year. I know that you'll have plans over the next couple of years to kind of move to nearly all electric in the field and you've got some electric substations that are going to be installed over the next few years. Can you just kind of talk to maybe the timeline of how all that stuff sort of plays out? When those like substations get installed and when, realistically, you could be nearly all electric in the field? Just how that sort of timeline looks.
Sure. And I think '23, I'd call, would be a transition year. So I think we'll -- and maybe I've mentioned on previous calls that this year, we're virtually running everything on diesel. Next year, you will see us as we get these [ e-fleets ] in some dual fuel, engine and fleets going forward that will probably be kind of that transition of Part diesel, part CNG is where we're headed. And then as these substations get built, we'll be able to start doing more of our operations. It won't be 100%, but more of our operations on [ highline ] power when we get to 2024 and then continue to move closer to 100%, '24, '25, '26-time period.
But I think that's the general evolution. Obviously, the [ e-fleet ] activity to become longer life engines, lower cost. And so it's better for emissions and better from a cost structure standpoint. So directionally, that's where we want to go. It's just going to take time to get there. And really waiting on the build-out of transmission and then what's that -- if everybody does it, the power demand is going to be higher. So we need power generation to come online as well.
Next, we'll hear from Doug Leggate of Bank of America.
Rich, I wonder if I could just pick your brain a little bit on the, I guess, it's on the philosophy behind the way you're going to develop the asset going forward. Was this a surprise to you that the deferral, I guess, is going back to the deferred targets resulted in lower productivity? Is that something that you anticipated? And I guess, what I'm really trying to get to is, when you think about your capital program going back to the -- for one of our expression, cube development. Are there any impacts on your capital expectation relative to the deferred target or a delayed target philosophy you have previously?
Yes, I'd say the delayed targets have underperformed where we would have anticipated. They still have great returns. It is just we have better locations in our portfolio. And so as we've gotten those results over the course of this year, we've decided that, that's not satisfactory to us, and we want to move forward to higher thresholds. And so we've just reshuffled the deck, as I said earlier, and are moving to full stack basically across the field. But -- and not -- and we'll defer those delayed targets to a later date down the road. So really, that's been the game plan and the learnings that we've had this year as we get smarter and better as we move forward.
But to be clear, presumably, you had the benefit of existing pads. So is there a capital implication for the change in the way you'll be developing going forward?
It's probably small, Doug, but it's not a significant -- the pad cost is relatively small in the grand scheme of things. So -- and in some cases, we were still having to expand tank batteries. So yes, to a small extent, but overall, I think you'll see that the new programs going forward are going to be more capital efficient than we were in '22, and which is the objective and higher productivity and better free cash flow generation.
That's what I was after. I'm sure Neal can wait for my follow-up is my cash tax question, Neal. And I wonder if you could just give us a quick update as to the NOL position. It looks like deferred taxes started to trend a little bit lower over time, at least based on the third quarter. So any help there would be appreciated on your expected timing.
Yes, Doug, I mean, we've essentially utilized our -- first of all, good morning. Yes, that's right. We've essentially utilized our full NOL balance. So we've got a little bit that we'll utilize here over the next several years. But for the most part, I'd model it is being utilized. If you look at our federal cash taxes paid to date, based upon estimated taxes, it was based on a higher commodity price earlier in the year. So you saw that change for Q4 guidance.
So based on our current commodity price outlook, which is lower based on where we were earlier in the year, we believe we have minimal remaining 2022 federal cash tax obligations. And then if you're going to fast forward to 2023, based on the strip, we'll be somewhere that, as I said before, mid to high teens.
Moving on to Scott Hanold of RBC Capital Markets.
Maybe just stick with the budget or 2023 a little bit and just a high-level budget. I think you've got some pretty good color. But when I think about sort of a 10-plus percent service cost inflation, and then potentially adding a couple of rigs. It kind of feels like a 4.4% to 4.5% kind of overall capital range, does that generally make sense? And can you talk about some pushes and pulls that may occur around that?
Yes, Scott. I mean, I think that's directionally right. I mean, we've talked about as we add those 1 to 2 rigs, those with where they sit today are kind of $175 million, $200 million capital spend, and then you have the 10% where we see that. So from where we sit today, it's at 3.6% to 3.8%, and add those increases to it, it gets you to that 4%, 5% general range. And we're still working on it. Obviously, increasing the return thresholds has implications to it and capital efficiency improvements. And so we're still working through all that. But I think directionally, you've got it right.
Okay. Appreciate that. And if I can go back to sort of the change in the drilling strategy and targeting higher return wells. And just at a high level, can you give us some sense of coming into 2022? When you laid out the program, and obviously, it wasn't as optimized at the end of the day. But where -- when you think about where you were targeting, was it generally kind of going back to existing areas where you've drilled wells to whether earn acreage or for whatever reason, and drilling in some of the, I guess, other not as core stack part of the portfolio? And in my kind of question kind of then thinks about like 2023 when you do the full stack development is really less about drawing some of those, say, other than the best targets versus more of the deferred completion impact?
Yes, Scott. I'd say when you got 1 million gross acres, we had our rigs spread out across the field to really handle all the things that you laid out there. But as we move that threshold to be higher, it focuses more on areas that have those higher rate of returns. So in general, that's going to move probably a little more activity to the north across the field. But that's really -- the allocation of capital here is really the focus in generating higher rates of return. And so that's going to drive it. The longer laterals, obviously, has a higher rate of return, as we talked about on the call. And so there's a focus on that. We're going to have over 100 of those wells in the 2023 program. And so that's really how we've gone about that selection, and we're just -- we're still doing the full stack. We're just prioritizing those wells that are -- those pads and locations that have higher rates of return.
Okay. Okay. So I guess my question was more specific on that illustration you have on Chart 11. So in 2023, we can expect you're targeting pretty much all of these 6 zones in the development program, right?
Absolutely.
[Operator Instructions] Moving on to Charles Meade with Johnson Rice.
Rich, my first question is kind of on the same lines of most of these questions you've got this morning. I think I heard you say in your prepared remarks that you were a little disappointed or your '22 program came in a little bit under where you thought. And so I wanted to understand, is the change that you're making in '23 essentially just reversing some of the changes you made for '22 versus '21? Or is there another dimension to your evolution here?
Yes, Charles, I'd say it's more about just the allocation of capital and moving to a higher return locations and areas. And so the returns that we are generating from the program in '22 are still fantastic. I mean, so I don't want anybody to take away that they're not great returns. It's just productivity came in a little less than we anticipated, and we wanted to rectify that and fix that and we weren't satisfied with it. And so we've got a depth of portfolio that we can move things around. And so we've made those changes. And going into '23, we're going to drill [indiscernible] wells that have higher productivity and higher rates of return, and that's really just what we're charged with from a capital allocation standpoint to make happen. And so that's where our focus is. And the team is highly focused on it, and we're going to execute that program going forward.
Great. And the second -- my follow-up is probably for Scott. Scott, I wanted to -- first off, congratulate you guys, they're buying back shares in the quarter. That's a great price that you guys were able to execute at. I just wanted to take your temperature and get an update from you on how you're thinking about the mix of buybacks versus variable dividends now.
As we laid out in our program, it's still heavily weighted toward dividends, which was all the feedback that we've been getting from our long-term investors over the last 3 years. So we'll continue with that. We got the balance sheet to be very opportunistic, obviously, and we've shown that also, and we'll continue that also.
And next, we'll hear from Derrick Whitfield of Stifel.
My first question, I wanted to ask on [indiscernible] understanding that you have limited exposure to Waha and the recent weakness is driven by maintenance with Gulf Coast Express and EPNG pipeline. Could you speak to your macro views on in-basin gas prices for 2023 and if [indiscernible] tightness could lead to shut in for some of your peers?
Yes. I mean, obviously, we've got pipelines coming in incremental compression coming. But as you can look at the forward curve on Waha prices out there, I mean, obviously, they're trading at a discount to [ IMEX ] and SoCal and other places. For Pioneer specifically, I think we've talked about having about 25% in that range of exposure to Waha. It's been a little bit higher because of the SoCal maintenance on El Paso being down. We haven't been able to move as many volumes out west as we would have liked. But we've got incremental capacity on firm transportation coming in '23 and then more in '24 when Matterhorn comes on. We're also moving our Parsley and DoublePoint volumes that were on Waha. We'll be moving them out of basin in '23, '24-time period as well as we take those volumes in kind.
And so from Pioneer standpoint, we'll have very little exposure kind of in that late '23, '24-time period at Waha is for us. Others, it is -- for those that are smaller operators that don't have firm transportation, obviously, they're going to -- until those new pipes come, they're going to probably be getting discounted prices. And we'll see. I mean, I haven't seen any or forecasted seeing any shut-ins at this point, but that could be an ultimate result for [ some ]. But at this point, I'm not aware of any that are expected.
That's great. And perhaps for my follow-up, I wanted to go back to Slide 11, and just wanted to focus on your new economic threshold commentary. Could you help frame the degree of increase in returns you'd expect to see in that 2023 to 2027 program? And what percent of your 20-plus year inventory falls into that category?
Yes. I mean, it's a meaningful increase from where we were in '22 to what we're doing in that '23, '27-time period. And just given the depth of our inventory, we've got 15,000 Tier 1 locations there. So we've got a long runway to execute at that same economic threshold that we've set to get these higher returns and higher productivity. So we're blessed to have the inventory we have, and we can execute this for a long period of time.
Next, we'll hear from Arun Jayaram with JPMorgan.
Rich or Scott, I was wondering if you could just help us understand what the new IRR and return on investment thresholds are that you shifted to.
Yes, Arun, I guess just -- like I said in the last question, it's really -- we've made a meaningful impact to increase them, and that threshold is really what we're building our 2023 and subsequent year programs on. And so it's a substantial shift, I'll tell you that. And I think you'll see from that Slide 11 has demonstrated there that the productivity is getting higher and capital efficiency, therefore, will be better and our free cash flow generation will be better. So that's really been the focus of the team as we've -- as I said before, not been satisfied with our '22 results. And we've made a dramatic shift to improve that.
Understood. And just maybe a follow-up, Rich. Just looking at some of the historical data in the Northern Midland Basin, between 2017 and 2019, Pioneer was completing about 85% of its wells in the Wolfcamp A and B intervals. That decline to, call it, the mid to upper 60s between '22 and '21. This year, in '22, you've done about 51% of your wells in the Spraberry and less than half in the Wolfcamp A and B. So is the plan on a go-forward basis to shift back to a higher mix of Wolfcamp A and B wells consistent with the previous years? Or is it you're targeting new zones? I just trying to -- new areas? Just trying to understand what shifts in early 2023.
I think it's more of a geographically where we're drilling. And I think you're still going to see us, I mean, as you know, across the field. Some zones are more prolific than others. And so, in general, for the '23 program, I haven't looked at it specifically, but I think it's going to be probably in that -- I think it's going to be probably evenly split between Spraberry and Wolfcamp zones for the most part. Maybe it's slightly weighted towards the Wolfcamp zones as we look at that program, but it will be area specific, and we're going to maximize the returns by each zone given in the different areas across the basin.
Moving on to Matt Portillo with TPH.
Just a quick question around spacing design. You've had an extremely consistent spacing design on a horizontal perspective over the last couple of years, which has led to pretty consistent well results in the Wolfcamp, in particular. I'm curious, as you've gone to full field development, are there any learnings on a vertical basis in how you guys think about vertical communication moving forward from a spacing design perspective?
Matt, we continue to learn like everybody as we go. But in general, I'd say our spacing really hasn't changed that much. I mean, it's still generally rule of thumb, 800 to 900 feet spacing on the wells here and there. It's different as we learn new things. But if you think broadly across our acreage position, it really hasn't changed over the last 2 or 3 years at all. So I don't -- nothing big as I would characterize it.
Perfect. And just a follow-up on the differentiation between zones. Again, I know there's a lot of noise in the state data. The Wolfcamp results have generally been pretty consistent, it looks like the Spraberry may be a bit more volatility in the data set over the last few years. As you guys look forward into 2023 and that improvement in the overall development program. Is part of this just some high-grading occurring in the zones you're focused on in the Spraberry moving forward? And any color you can kind of give around just some variances we've seen in the Spraberry data over the last couple of years?
Yes. I think on the Spraberry data, some of it will depend on whether they were full stack development or single targets or delayed targets. So you just get different data based on the vintage of when those wells were completed. Overall, on our program, the threshold applies on a kind of a per zone per well basis is how we've [ stayed ] up. So in areas where zones are less prolific, then we will drop those from the full stack development.
And so it's really just a case that we'll continue to maximize value in how we select the wells across each of those pads in full stack. So it's a full economic analysis that kind of give us the highest rate of return and the highest productivity that we're looking for.
Next, we'll hear from Leo Mariani with MKM.
Just in terms of the 2022 program here, just looking at kind of the data in terms of well POPs to date. Are we looking at kind of a pretty meaningful step down in the fourth quarter in terms of POPs? It looks like if you do see that step down, you'll kind of still be at the high end of the range? Or you think just based on how the program is going, it sounds like you're still running 20-something rigs that maybe we'll get a few more POPs than the guidance here in '22?
No, Leo, I think you're right. I mean the plan all along [ had ] is having less POPs in the fourth quarter. So we're going to be roughly, call it, 25 POPs less in the fourth quarter than we were in the third quarter just by the nature of the plan and just timing of how it's working out. So I wouldn't read anything other than that. I just say it was planned in timing, and that's where the program shakes out for Q4 and laid out in our guidance.
Okay. That's helpful. And then just wanted to ask a little bit on oil cut. Just kind of looking at the guidance here for fourth quarter. High level, it looks like you are expecting maybe the oil cut to come down slightly in terms of where it was in 2Q and 3Q. Just wanted to get a little sense in terms of why the cuts kind of been coming down during the course of '22. And then in '23, do you guys have kind of a rough estimate of what you think the oil cut might be? Do you see that maybe improving a little bit with kind of the high grading of the wells? Any color would be appreciated.
Yes, sure. You're right. I mean, our general forecast has been in that 53%, 54% oil range. I don't anticipate it changing. [ Much ] -- it's come down over the years as we -- just the GOR of these wells continues to grow. It hasn't changed our oil forecast at all, but the gas continues to come out of solutions. So that's just part of what we've been getting. But in general, I would think as you think about '23 programs to be in that same 53%, 54% range.
And next, we'll hear from Neal Dingmann with Truist Securities.
Nice quarter. First, just a quick one, you guys on just the continued development. Scott, I think last time you mentioned on the call, the tackling a couple of gas wells -- next year you're targeting a couple of gas wells in the Woodford, Barnett. Could you just say your thoughts on that? Obviously, gas continues [ to do ] very well. And so I'm wondering, is that still the plan and sort of the rationale behind that?
Neal, it's Rich. Yes, we still plan on testing a couple of wells in each of the Woodford and Barnett zones next year. That's part of what we're planning forward. We expect those wells, obviously, to be -- as they're deeper to be gassier. And we're really -- we will find resource there. And so it really just what's the productivity of those wells. And given where gas prices are maybe lower Waha today, but where we expect them to be longer term in the forward curve. We just want to understand what that resource is. And so we think it's worthwhile to spend some capital next year to test those, and then we'll see what the productivity looks like and go from there.
Makes sense. And then Rich, while I have you, maybe just a follow-up is just, what do you all think -- I know you talked about DUCs or the POPs going down a little bit. DUCs at the end of the year, will it just sort of be a normal level? Or what could you comment on how that you would have? I don't know if you think about having a little bit more than normal because of the timing and it might help a little bit and started in '23?
Yes, I don't think it will be materially different than just our normal working capital of what I'd call DUCs that are pads that are ahead of the frac fleet. So nothing that is going to be a big change from where it's been through most of the year. So it will be business as usual is how I'd put it.
And next, we'll hear from Bob Brackett with Bernstein Research.
Question coming back to the relative underperformance of the delayed target strategy. Could that just simply be that the frac heights and the initial wells exceeded their target zones and you're getting some contributions from those delayed targets. What's the responsibility of that?
Bob, I think there's definitely some level of communication. And so we've seen that as the reservoirs we've come back and done those delayed wells. And so that's impacted the productivity some from those wells that we didn't anticipate. But at the end of the day, like I said earlier, the returns have been still very, very strong returns on those delayed wells, and there's still plenty of resource there. It's just we can get better returns by moving to the full stack in other locations.
That's clear. But the other question would be, clearly, your opportunistic share repurchases have been effectively retiring shares at a low price. How do I respond to the buy side that argues, well, Bob, you've got a $283 target price. Pioneer, who knows more about Pioneer than anyone is buying in the 220s. So no, thanks.
We're always -- I mean, it's -- we run NAVs on all of our -- on our assets, and I think it's better. We're always going to buy a little bit each quarter. But I'd rather be stronger and try to buy the stock at a discount. So that's just the way we are, so.
And as a follow-up to that, look, in terms of the conversations that we've had with our shareholders and their desired method of return of capital has been primarily, as we've discussed, the base dividend, combined with the variable dividend. That takes you to 80% of free cash flow. So the majority of the free cash flow is spoken for. And that being said, even over and above that, we've been very opportunistic and not shy to deploy that capital incrementally to buy back shares. So we do step into the market and repurchase equity. It's just that the return to capital, as it's been communicated to us by our shareholders, there has been a preference for the base plus the variable. So that's a big part of that rationale, of course.
And you've got to look at the total stock return. You take our current -- we paid out $26. So people, when you look at a total TSR, a lot of charts don't show that $26 payout. So you just got to think about that also, Bob, so.
And moving on to Phillips Johnston with Capital One.
Rich, just a follow-up on Arun and Matt's questions. It sounds like there's clearly a geographic mix shift element to the new approach. And if I heard correctly, you aren't necessarily changing the mix of zones within any given area. So there's no real mix shift towards Wolfcamp and away from Stackberry. But it sounds like you are just going to sort of be more selective within a given section. Is that correct?
Yes. I think, just given our expansive acreage position that we will move things around to maximize the return thresholds by the geographic areas where we're in. So yes, as I mentioned, I think there's definitely -- we're going to go to locations in areas that have the highest rates of return, and that will move to the certain extent a little bit north.
Okay. So is that going to wind up, I guess, yielding fewer wells per section?
No, I don't think it's changing what we're -- I mean, we're not changing. Like I said earlier, the spacing on the wells, anywhere, it's just going to those higher productivity areas that were -- and therefore, has higher rates of return that we're targeting. And so -- but it's not really -- like I said, it's not changing our depth of inventory or how long it's going to last. It's just what we're drilling today versus what we're drilling tomorrow. So we've just deferred some things that we had in the portfolio that we're going to push back in time and bring some things forward that have high rates of return.
And we have time for 1 final question. Jeanine Wai with Barclays.
Our first question is on the renewables update that you provided. Just wondering if you could give a little bit of commentary about any capital requirements that come with those projects? And anything around maybe the economics or the cost of the electricity that you're going to be buying relative to what you would be paying if you didn't have these agreements?
Sure, Jeanine. In terms of capital, I mean, NextEra is developing the project on our surface location and on the Concho Valley one that's being developed by them. And so no capital from our side that's going to be investing in that. We are signing like, as you mentioned, power purchase agreements to take that power. And based on where the forward curve on the electricity market looks like, these are at favorable prices to that. So we're excited to get those projects on it and get the benefit of that power purchase agreement pricing. So they're good pricing is the way we look at it. And then on top of it, we get the renewable energy credits that come with that, that can reduce our Scope 2 emissions. So overall, we think it's 2 great projects and look forward to doing some more.
Okay. Great. And then as the second question, I apologize for going back to the full stack development topic and if I missed this in another question. But we love our fun with maps. And just wondering if you have a rough estimate of how much of Pioneer's overall acreage is virgin, would qualify for more virgin stack development versus something that would be more impaired?
Jeanine, I don't have you a rough estimate. I mean, just given the size and scale of our footprint, I would say there's still a significant amount of virgin. But I don't have a percent that I could quote there. I would just be guessing, and I don't want to do that. So we can probably find it, but I don't know that off the top of my head.
And that's all the time we have for questions today. We'll turn the conference back over to Scott Sheffield for any additional or closing remarks.
Again, thank you very much for participating, and everybody over the next couple of months have a Happy Holidays and travel safely. Thank you.
And that does conclude today's conference. We thank you for your participation. You may now disconnect.