OXY - NYSE

Good afternoon, and welcome to Occidental's Second Quarter 2023 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Neil Backhouse, Vice President of Investor Relations. Please go ahead.

Thank you, Drew. Good afternoon, everyone, and thank you for participating in Occidental's Second Quarter 2023 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Rob Peterson, Senior Vice President and Chief Financial Officer; and Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management. This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. We'll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules to our earnings release and on our website. I'll now turn the call over to Vicki. Vicki, please go ahead.

Thank you, Neil, and good afternoon, everyone. There are 3 things I'd like to drive home today. First, our portfolio of assets continue to set the table for record results. Second, our teams outperformed last quarter's and last year's excellent operational metrics. And I want to make sure our investors see how that flows to the bottom line. Third, our strategic and operational improvements continue to support our ability to take actions to drive even better shareholder returns. I'll begin with the portfolio. We had the highest quality and most complementary assets that Oxy's ever had. They are a unique blend of short-cycle, high-return shale assets in the Permian and the Rockies along with lower decline, solid return conventional reservoirs in the Permian, GoM and our international assets. 60% of our oil and gas production is from shale reservoirs and 40% from conventional. More than 80% of our production is in the United States. The international oil and gas assets that we operate are in only 3 countries, Oman, Abu Dhabi and Algeria. Our worldwide full year 2023 production mix is expected to be approximately 53% oil, 22% NGLs and 25% gas and 70% of the gas is in the United States. Our conventional oil and gas assets, along with OxyChem provides support during low price cycles while the shale assets provide the opportunity for growth during moderate and high price cycles, and the flexibility to adjust activity levels quickly if needed. This combination of assets has generated record cash flows for Oxy over the last couple of years versus the cash flow generated by the portfolio that we previously had in a similar price environment from 2011 to 2014. The midstream business provides flow assurance and has done so with exceptional performance during catastrophes and emergencies. The low carbon ventures business will help Oxy and others decarbonize at scale in a way that provides incremental value to our shareholders. To summarize, we have a deep and diverse portfolio, providing the cash flow resilience and sustainability necessary to support our shareholder return framework throughout the commodity cycles. Let's shift now to operational excellence. Strong second quarter operational performance exceeded the midpoint of our production guidance by 42,000 BOE per day, enabling us to again raise full year production guidance. In the Rockies, outperformance was driven by improved base production and new well performance, along with higher-than-expected nonoperated volumes and the receipt of accumulated royalties. Our Rockies teams drilled 32% faster on a foot per day basis than they did in the first quarter. The team's diligent work set several new Oxy records, including company-wide record of drilling over 10,400 feet of lateral in only 24 hours. Just 10 years ago, it took the industry an average of 15 days to drill 10,400 feet. Our Permian production delivered higher operability and better-than-expected new well performance, particularly in our 2 new drilling space units in New Mexico, top spot and precious. Our Delaware completions team shattered Oxy's previous record for continuous frac pumping time by nearly 12 hours for a total of 40 hours and 49 minutes. Four years ago, the same job would have taken about 84 hours. 40 hours back then was unthinkable, but our teams have made this a reality. We expect that the efficiencies generated by advancements in drilling and completions pumping will result in lower cost and reduce time to market. Offshore in the Gulf of Mexico, we safely completed seasonal maintenance activities focused on asset integrity and longevity. Excluding the impact of this planned maintenance, we delivered higher base production and benefited from improved uptime performance across multiple platforms. Internationally, our teams continued to deliver strong results. The Al Hosn expansion came online 2 months earlier than planned, as a result of great teamwork with our partner, ADNOC. This means that together, we have now successfully expanded the plan in stages from 1 Bcf a day to 1.45 Bcf a day or a very small incremental capital investment. In Oman Block 65, we drilled a near-field exploration well, which delivered 6,000 BOE per day and a 24-hour initial production test, and it is now on production to sales in less than a month from completion. This was our highest Oman initial production test in the decade, and we continue to show the benefits of our subsurface characterization techniques worldwide. We were awarded the block in 2019 and in collaboration with the Ministry of Energy, we are positive about opportunities in the country where we are the largest independent producer. OxyChem also outperformed during the second quarter due to greater-than-expected resilience in the price of caustic soda and reductions in feedstock prices. OxyChem is one of our valuable differentiators. It provides rich diversification to our high-quality asset portfolio by consistently generating quarterly free cash flow which provides a balance of our oil and gas business throughout the commodity cycle. Now I'd like to talk about how our focus on operational excellence is enhancing our portfolio and extending our sustainability to maximize near- and long-term shareholder returns. Oxy's wells are getting stronger and are supported by our deep inventory, which continues to get better. In the Permian, we have improved well productivity in 7 of the last 8 years. And with the application of our proprietary subsurface modeling, we're starting to see the same results in the DJ Basin, where improved well designs have delivered reserves at roughly 20% less cost. The improved well design has resulted in about 25% improvement in single well 12-month cumulative volumes over the last 5 years. And we are on pace to significantly exceed that rate in 2023. In addition, our teams are continuing to advance our modeling expertise, which has led to upgrades of secondary benches to top-tier performers. This was the key for our -- sorry, 212% U.S. organic reserves replacement ratio last year. Let me try to make that point again. Last year, because of these upgrades to our secondary benches to our top-tier benches, we were actually able to replace our production by 212% with reserve adds. Secondary bench upgrades are progressing in 2023. Overall, in 10 of the last 12 years, we have replaced 150% to 230% of our annual production. The only exceptions being in 2015 with a price downturn in 2020 with a pandemic. Converting lower-tier benches to top tier will further extend our ability to achieve high production replacement ratios. Not only are we adding more reserves than we are producing each year, we're adding the reserves at a finding and development cost that is lower than our current DD&A rate, which will drive DD&A down and earnings up. Our differentiated portfolio and the strong results delivered by our teams provided support for execution of our 2023 shareholder return framework. During the second quarter, we generated significant free cash flow, repurchased $425 million of common shares and have now completed approximately 40% of our $3 billion share repurchase program. Common share repurchases, along with our dividend enabled additional redemptions of the preferred equity. To date, we've redeemed approximately $1.2 billion of preferred equity. I'll now turn the call over to Rob.

Thank you, Vicki, and good afternoon, everyone. During the second quarter, we posted an adjusted profit of $0.68 per diluted share on a reported profit of $0.63 per diluted share. Difference between our adjusted and reported profit was primarily driven by impairments for undeveloped noncore acreage and deferred tax impacts from the Algeria production sharing contract or PSC renewal, partially offset by an environmental remediation settlement. In the second quarter, strong operational execution enables over $1 billion of free cash flow for working capital despite planned maintenance activities across several of our oil and gas businesses. Following nearly $1 billion of preferred equity redemptions and premiums, $445 million of settled common share repurchases and approximately $350 million related to LCVs investment in net power, we concluded the second quarter with approximately $500 million of unrestricted cash. We experienced a positive working capital change during the second quarter primarily driven by reductions in commodity prices and fewer barrels in shipment over quarter-end. Interest payments on debt are generally paid semiannually in the first and third quarters, which also contributes to a positive second quarter working capital change. During the second quarter, we made our first U.S. federal cash tax payment this year of $210 million and state taxes of $64 million, which were netted out of working capital. We anticipate a similar federal cash taxes we made in subsequent quarters this year, those state taxes are paid annually. Our second quarter effective tax rate increased from the prior quarter due to a modest change in our income jurisdictional mix. The proportion of international income, which is subject to a higher statutory tax rate grew during the second quarter. We are therefore guiding to a minimum adjusted effective tax rate of 31% for the third quarter as we expect our effective tax rate going forward will be more closely aligned with the second quarter rate. I will now turn to our third quarter and full year guidance. As Vicki just discussed, our technical and operational excellence continues to drive outperformance across our oil and gas businesses. This enables us to raise our full year production guidance midpoint to just over 1.2 million BOE per day in anticipation of a strong exit to the year. Rockies outperformance serves the largest catalyst to our full year production guidance raised and is also a primary driver of the slight change to our full year oil mix guidance. Reported production in Rockies is expected to reduce to its lowest point this year in the third quarter before beginning to grow in the fourth quarter. In the Gulf of Mexico, we were guiding slightly lower production in the third quarter compared to the second quarter due to a contingency for seasonal weather. The third quarter weather contingency as well as planned maintenance opportunities brought forward to reduce overall downtime are expected to result in our highest domestic operating costs on a BOE basis this year when normalizing to less than $9.50 per BOE in the fourth quarter. Internationally, we expect higher production compared to the first half of 2023 due to plant turnaround and expansion project timing ? Al Hosn as well as impacts from various international production sharing contracts. As we have previously mentioned, the increased international production will be slightly offset by the new Algeria PSC, which decreased reported production, but the reduction in imported barrels is not expected to have a material impact on operating cash flow. Overall, the first half of 2023 was characterized by strong production in Gulf of Mexico, Permian and Rockies, with latter 2 businesses also benefiting from nonrecurring production events. We have better anticipated wells and time-to-market momentum year-to-date, which we expect it to be benefiting from in the second half of the year, the third quarter will be the only quarter in the year where production average is below 1.2 million BOE per day. Reduced production is mainly driven by the previously mentioned weather contingency implies to the Gulf of Mexico. The decrease in third quarter production will likely result in total company production and is lower in the second half of the year when compared to the first. However, the change in expected production does not represent a shift in our volume trajectory. We anticipate fourth quarter production will be similar to the first 2 quarters of 2023, and we expect to enter 2024 with a strong production cadence. Furthermore, our full year guidance implies our fourth quarter output of approximately 53%, largely due to improved GoM production [Indiscernible] weather contingency. Shifting now to OxyChem. As anticipated in original guidance, we continue to see weakening in the PVC and caustic soda pricing during the second quarter. However, our full year guidance remains unchanged at a pretax income midpoint of $1.5 billion which will represent our third highest pretax income ever in another strong year for OxyChem. We also expect our chemicals business to return to a more normalized seasonality compared to recent years, meaning that the fourth quarter will represent the lowest earnings for the year. As we have mentioned on previous calls, the fourth quarter is typically not a reliable roll forward for the year ahead through the inherent seasonality in the business. We revised our full year guidance from midstream and marketing due to expected market changes over the second half of this year. The margins generated by shipping crude from Midland to the U.S. Gulf Coast are expected to compress further following the annual FERC tariff revision, which has increased our pipe cost approximately $2.55 a barrel. Over the same period, the price we market long-haul capacity is expected to decrease. Additionally, we anticipate fewer gas market opportunities as spreads across multiple basins have continued to narrow and find opportunities generated in the first quarter. Also, pricing for sulfur produced at Al Hosn is expected to soften in the second half of the year. Capital spending during the quarter was approximately $1.6 billion. We expect capital to decrease slightly in the third quarter with a more pronounced reduction in the fourth quarter. The expected decrease was primarily driven by reduced working interest and gross activity in the Permian, which is in alignment with our original business plan. We anticipate receiving $350 million during the fourth quarter associated with the second quarter [Indiscernible] settlement. While this settlement will drive our -- report it overhead down, our full year guidance to overhead expense on an adjusted basis remains unchanged. Turning now to shareholder returns. As Vicki mentioned, we further advanced our shareholder return framework during the second quarter through the repurchase of $425 million of common shares, which enabled additional preferred equity redemptions. After a strong start in the first quarter, we triggered the redemption of over $520 million of preferred equity in the second quarter. Year-to-date, we've been approximately $1.2 billion or 12% of preferred equity that was outstanding at the beginning of the year with 10% premium payments to the preferred equity holder of approximately $117 million. Preferred equity redemptions to date have resulted in elimination of over $93 million of annual preferred dividends. As of August 2, rolling 12-month common shareholder distributions totaled $4.08 per share. Due primarily to the concentration of share repurchase in the third quarter of 2022, coupled with the current commodity price curve, it is likely that the cumulative distributions will fall below the $4 per common share during the third quarter. If we drop below the $4 redemption trigger, our ability to begin redeeming the preferred equity, again, will heavily be influenced by commodity prices. The EPI prices would likely need to be higher than what the forward curve presently indicates for us to remain above the trigger for the remainder of 2023. Even if we aren't able to continue redeeming the preferred equity for a period of time, we remain committed to our shareholder term program, including our $3 billion share purchase program. Our basic common share count is at the lowest since the third quarter of 2019, resulting in per share earnings and cash flow accretion to our common shareholders. Sustained efforts to significantly deleverage over the past several years have improved our credit profile, culminating a return to investment-grade status when the Fitch ratings upgraded Oxy in May. We believe that our investment grade credit range reflect our exceptional operations, diversify the high-quality asset portfolio and our commitment to pay down debt as it matures. Our second quarter results and our full year guidance demonstrates solid progression towards another strong year for Oxy. We look forward to reporting on additional progress as the year advances. I will now turn the call back over to Vicki.

Thank you, Rob. Before closing today, we'd like to briefly mention 2 low carbon ventures announcements that we made this week. We were glad to announce that Japan's ANA Airlines became the first airline in the world to sign a carbon dioxide removal credit purchase agreement from our subsidiary, 1.5. We're excited about that and happy to work with them. We're also pleased to announce a first-of-its-kind agreement with our long-standing partners, ADNOC, to evaluate investment opportunities in direct air capture and carbon dioxide sequestration hubs in the U.S. and the UAE. With this agreement, we intend to develop a carbon management platform that will accelerate our shared net zero goals. We have many exciting developments taking place in LCV, and we look forward to providing you a more comprehensive update towards the end of this year. With that, we will now open the call for questions.

[Operator Instructions] The first question comes from Doug Leggate with Bank of America.

Vicki, I wonder if I could focus on productivity which your latest slide deck is showing -- you refer to it as the wedge wells with a quite frankly, stunning step-up in performance relative to prior years. My question, I guess, is the repeatability of that and the impact on how you think about your strategy? Because to summarize, you've suggested you would not seek to grow production meaningfully, if I'm interpreting that correctly. But this productivity would suggest that either you're going to grow production as you did with your step-up in guidance or you're going to cut your capital budget to hold the production at a flatter level. So I'm curious, are you prepared to take the production? Or is it going to get more capital efficient with lower CapEx?

Well, we intend to keep our capital plan as we had it or at least the activity plan as we had it. I can tell you, Doug, I'm incredibly impressed with what our teams have done. I've been in this industry for a very long time, and I've seen a lot of extensive work done to model conventional reservoirs over the years. And when we started our shale development, some thought it was more of a statistical play where you just go drill a 100 wells and maybe 25% of them would be really good, and 75% would be okay. But we took the time in 2014 to step back and say that we were going to put together a team that could do the kind of work that needs to be done in shale. It's much more complex than conventional. So we really focused on trying to make sure that we put together a team that could do the most sophisticated work on the subsurface possible, and they've done incredibly well. And I would say, in the past 2 to 3 years, I was thinking that we were getting close to plateauing on our learnings and what we can do. But the teams continue to surprise me, continue to go beyond what I thought we would ever be able to do in this industry with respect to not only understanding the subsurface as well as we do, but also being able to understand how to get the most oil out of it. And -- so where we are today is, I've now asked the teams to stop talking about it. We for years, we're sharing things that we were doing, and we've shared some things on the slides in the slide deck, but they had prepared a lot more to share with you today, to highlight and map out the pathway that we're using to get to where we are. But it's just too important to our company, it's -- and to our shareholders to keep that proprietary because this is something that's pretty phenomenal, I think. And now we're taking this, and we're going to apply it to the Permian -- I mean to the Powder River Basin. We're using it. They've done incredibly well in the Permian. We've also taken learnings from the team in the DJ and moved those through the Permian. So we're sharing ideas across business units. The next one will be the Powder River basin, where while we did take an impairment on some noncore areas, we are excited about the Powder River. And I think Richard will say a little bit more about that later. But the Southern Powder River is, we're seeing good results there. And our appraisal team is beginning to work in the northern part of the Powder River. And we're going to take it also the same sort of concept about how to do it, we want to take to other areas within Oxy. And we think that by using a similar methodology with what our phenomenal team in the Gulf of Mexico has been able to do, they've done amazing things in terms of being able to see below-the-salt and to improve our success rate there. But I think you put this subsurface team for our shale development, but the approach they take, the methodology that they use with the ideas that our GoM team has generated and start really exploring the various strengths, I think we take this and apply it to conventional reservoirs and applying this to conventional with the expertise that we have working those conventional reservoirs today, I think that there would be even more cross flow of learnings from conventional to shale and shale and conventional. I think it's beyond what anybody in the industry that I've seen or heard about it is doing today. So with that said, to get back to your question on capital and production, we're going to execute our program, looks like it is going to result in a production increase, and we're happy with that. We never said that we didn't want to grow. We just don't want growth to be the target. But the target is value creation. And that value creation comes from doing the developments when we're ready to do them at the pace that generates the most net present value. And our teams are doing that, and they're doing it incredibly well. So we'll take what we're getting here.

I've got a very quick follow-up, and it's kind of hard that -- something we've talked about before, which is the legacy Anadarko portfolio. We know it dips in the second and perhaps the third quarter. My question is, when you rebound out of the fourth quarter as is ordinarily the case in that profile, have you lost any production capacity? Do you -- what do you think the production capacity is today? And presumably, those are the highest margin assets in your portfolio. I just wonder if you could confirm that so we can anticipate what happens to earnings and cash flow in Q4?

Yes. The legacy Anadarko assets in the Texas, Delaware are really, really top tier. We had -- when we were working to do the acquisition, we knew that they were really good. We thought they would come in and be almost equal to our Southeast New Mexico, and I'm going to get myself in trouble here. I think they were, I thought, for a while better than Southeast New Mexico. I think I happen to say that in the hallway one day, and the Southeast New Mexico team decided they would prove me wrong on that. So I would say that Southeast New Mexico and Texas Delaware are both incredibly important to us. They are very high quality, and they're both a part of our program going forward. Richard, you had something to add?

Yes. Maybe just to help add on to that when we talk about assets in the portfolio and even legacy Anadarko. I think the Rockies trajectory, while very strong in the first half of the year, I think what's impressive, we talked about knowing we would decline kind of through the first half of the year and then grow. And I think if you see our guide for 3Q and then implied guide for 4Q, that not only was the first half better, but the second half was better as well. And while the new wells are certainly core, how do we think about deploying capital and creating the efficiency, I'd like to also recognize all the team that works on our base production. I think the Rockies is a great example of being able to rethink our surface infrastructure, they've been able to kind of lead the industry, I think, in some of these tankless designs, but they've migrated to more efficient bulk and test. They've been able to think about artificial lift earlier, things like gas lift earlier in the cycle of the well. And a lot of that beyond creating the most EUR per dollar spent is really helping our production. And so when you look year-on-year, that base production is another one that I think we're really proud of from the teams.

No doubt, it's the Permian and the Rockies and the Rockies actually applying artificial intelligence to their pumps up there, which has been very, very impressive as well as the management of the gas lift in the Permian, Texas and New Mexico. So these are exciting things for us, and we're -- we have to definitely gets kudos to the teams. They've gone above and beyond expectations.

The next question comes from Neil Mehta with Goldman Sachs.

Yes. [Indiscernible] to start off on the return of capital. Just curious on your thoughts on the commodity price level or the oil price level at which you believe you can get back to taking out the preferred. And just in the absence of that, how aggressive can you be around buying back stock?

Well, certainly, we have the capability at almost any price environment. There's a lower limit to where we would probably not do much share repurchases at $60. But at $70, we could continue a common share purchase program. And certainly, at $75 and above, we've got the cash to do both. But what we feel like with our current shareholder framework is that share repurchases are a big part of that because our -- in common share repurchases because what we're really trying to do is we're trying to create value per share for our investors. And to create value per share, it not only means that we need to grow production a bit. Again, that's with the cash flow is the main thing we're trying to grow when we're growing production, and that's an outcome of our capital program. So this year, we will get incremental earnings growth from our incremental volumes, but also developing our reserves at the lower cost, like we've talked about and like I talked about in the script and like we've been talking about here, what the teams are doing that's so important is to develop reserves, replace our production every year by at least 130% to [150%] And again, we've seen years up to 230%, where the DD&A or the funding and development cost is $6 or less in some cases. And we were able to do that with the DD&A rate of what we have today versus that, that's creating value for our shareholders, creating earnings. And then the last thing is to couple with the cash flow growth and income growth from the volume creation and the reduced cost of those binding and development reserves is to buy back shares. And especially given the fact that we feel we're very undervalued right now. So share repurchases, whether or not it triggers the preferred is really important to us. But in the near term, what we'll do is we will probably wait a little period of time here to watch what's going to happen with the macro. And if the macro plays out the way we expect, we should be able to do both to buy common and to get back at some point within the next few months to doing both buying not only common, but triggering the preferred, it could take into next year before we're able to get a program going. But we do believe that we can at $75 or above, have a program that will do that.

I'll just add that part of the challenge that we have is that our program last year was very back-end weighted. We did $2.4 billion of share repurchases concentrated across the second half of the year of $1.8 billion of that just in the third quarter alone. And so it's the pace at which we were able to retire shares last year, matched up against the commodity prices that we have this year, that's really making it difficult to stay with the 4 consistently. So if you look back to last year, gas pricing, we realized over $7 in Q3, oil prices were over $95 realized in Q3. And so that's the big change year-over-year that we're seeing.

And then the follow-up is congrats on getting the Al Hosn gas expansion on this year. Just would love any perspective or thoughts on your Middle East business and how we should think about the incremental cash flow associated with the asset that just came online?

The Al Hosn project getting to the 1.45 Bcf a day had very little capital, is definitely a good project for us. And with -- just having gotten that back on, we expect that the certainly, the production looking good towards the rest of this year from Al Hosn and also the fact that we were in Oman, able to get an exploration well that was record setting for us online and to production in less than a month was another good sign for healthy production coming out of the Middle East. We do have incremental opportunities in Oman for additional wells that are similar to that in Block 65. So -- and this year, this past year, in Safah field on the north Oman. We've set the production records there, and that's a field that's been in operation for over 40 years. So we're still finding new things to do there. And also, when I talk about innovation and subsurface modeling and with -- and Richard brought up the guys that are working really hard base maintenance, on base production. I want to mention, too, that there's been quite a bit of innovation coming out of Oman as well, one being a process called Oxy jetting, where we go into -- you can do it in new wells or existing wells to go in and jet through the formation and with proprietary process we use there and get incremental production, and that's part of the reason that we were able to achieve record production from that area this year. So a lot of good things happening in our Middle East operations, and we're as I mentioned in my script, focused on 3 countries, and we feel like it is best not to be spread over a lot of countries, but to -- we like the fact that we are here in the U.S. and 3 countries internationally, and we'll focus on being the best we could be in those areas and eliminate or minimize distractions from anything else.

The next question comes from Neal Dingmann with Truist.

My question is on the Gulf of Mexico. Your production and incremental operations at GoM continue to look quite solid. I was just wondering how would you classify just current opportunities today in the Gulf? And could we see any notable change in activity there in the coming quarters?

I would say that I have -- my thoughts about the Gulf of Mexico have actually changed a bit over the past year. Originally, when we made the acquisition, our plan was just to keep production flat and use the cash flow to invest elsewhere. I do believe now, again, based on the technical excellence of our teams working at and the fact that artificial intelligence, I believe, is going to be -- advanced data analytics, I believe, is going to be a game changer for the Gulf of Mexico. And I believe our team has the capability and expertise to optimize the use of those tools. So I think that not this year or next year, but I do believe that looking forward in the next 3 to 5 years, the Gulf of Mexico could become more of a growth area for us rather than just a cash generator.

I agree. I like the opportunities there. And then secondly, just -- you talked around this already, but maybe just a little more detail on your slide now on the DJ, maybe about just well spacing and completion design there. I'm just wondering, have your thoughts -- you guys have been ramping that up. And I'm just wondering, as you have been ramping up, have the thoughts on space or completion design has changed going forward? I think like in recent months, I believe gas and other pads are, what about 12-well spacing. So I'm just wondering if there's any thoughts to change any of that?

Yes. Great. This is Richard. I'll try to take a few pieces of that. I mean very excited about the DJ, like I described, but the new well performance in the base. But I would say consistent with really what we've done across our reservoir positions and especially in the unconventional. It really starts with the challenge on the subsurface in terms of all the things you described, spacing, how many wells per DSU. And I think the teams continue to look at those opportunities. And as we noted, really thinking about less, I think moving from 18 to 8 to 12 wells per section allows us to deliver the same EUR for less cost. And I think just like we've done in the Permian, that's the right recipe. We have been able to use completions and really frac intensity to kind of turn up the lever to help capture those reserves without having to drill additional wells. So we've gone up to 1,500 pounds per foot, which is up about 30%, I think from our prior designs. As we think about spacing and inventory, the thing I would say is not every drill spacing unit is the same. So the geology changes, the development sequencing changes. And so there'll be areas where that may be different. I think just to kind of contrast a little bit, we highlighted the performing DSUs in the Delaware Basin, those are actually opportunities where we added wells per section. And we were able to do that again by looking at the unique kind of attributes of that drill spacing unit against the reservoir. And we're cautious with that, but we've been able to have real success, both horizontally and vertically adding those wells where it's warranted. But just the last maybe a couple of points in the DJ, again. It's sort of a holistic design that the operation's team's put together. They have done a lot to reduce time to peak production. So eliminating those surface constraints where they can really allow those wells to optimally flow. And then as Vicki described, longer term, these wells go from gas lift to plunger lift and being able to use analytics to not only be quicker in terms of our optimization, but actually predict failure mechanism so that we can deploy operations teams quicker. These are the type of things that just really excite us about how our teams approach really adding production at the right cost.

The next question comes from Michael Scialla with Stephens.

You talked pretty extensively about the improving well productivity, and I know a lot of companies have been talking about service costs softening here. Looks like 2024 consensus estimates right now, anticipate you're going to spend about 4% more next year than you did this year to keep production flat with the current level. So I know it's too early to give guidance for '24, but just want to get your view on that outlook.

What we're seeing is we're seeing some things start to plateau in terms of cost. We're seeing labor being still a bit tight. But there's also around labor though, we're not seeing as many people wanting to change jobs. It's just a matter of getting the skills that we need in the field, and that's where the big challenge is, to get truckers to drive trucks, and people to do the welding and those kinds of field jobs are so important to us. But I would think that what -- we're not -- while we're not seeing any reduction -- much reduction in service company costs, we don't expect that. But I don't think we've settled on expecting any kind of increase next year.

And I can add maybe just a few. I agree with Vicki. I mean, we're, one, really pleased with the efficiency of our operations. That's always our focus. And so really, the rigs we've added over the last 1.5 years, we've highlighted some of the kind of individual goals, but we're seeing productivity just from reducing nonproductive time, improved kind of efficiency of the operations continue. But as we think about going into next year, OCTG, seeing some relief, but that generally lags, sand kind of similar, and fuel, obviously is a component, which has been lower for us. So we're seeing those types of things come in a little bit lower. But we've got really, the opportunity to continue to work with the fleet we have. We're a pretty steady operational pace at this point, which is very different to where we've been in the last couple of years. And so for us, it's really an opportunity to kind of utilize the resources we have and really get that optimization down. So if we look next year, that's going to continue to be the challenge. We hope there's some pricing that can benefit both operator and service company as we look at longer term, but we're really anxious to keep working on the efficiency.

And Michael, this is Neil. I just wanted to add. We'll always encourage our coverage group not to rely too much on consensus for whatever time period. As you know, the further out it goes, the more sale data that can be in there. So just continue to have the conversations with us, and we'll guide at the appropriate time.

Got you. I guess just summing all that up, though, I guess based on those numbers that would suggest you'd need to spend more to keep production flat. Is it fair to say that feels conservative based on what you know today?

I would say we don't know that because we're continuing to get more barrels. I mean just look at the graphs where our teams are getting more production from the wells for either the same or lower cost. We're doing both. We're increasing efficiencies of execution while also getting more recovery out of the wells. So I don't think I'd be prepared to say that we'd have to spend more capital just to stay flat. We'll look at that. And again, the efficiencies that are being gained, I think we have to take all that into account. And we'll -- we're starting to look at some of that now, but I'm a bit impressed with what we've been able to do with the dollar to spend because I think that we still have for our wedge production, the lowest capital intensity on a per barrel basis in the industry, I believe, at least the last time we checked it. Now we haven't done that number in a couple of months. So we probably need to check that again to know for sure.

Appreciate the detail on that. The one to follow up on your agreement with ADNOC. Does that cover Stratos? And do you have any sense for what kind of capital the company is looking to spend with you at this point?

It doesn't cover Stratos, but it does cover other things, and it could cover things that we currently have today, not -- probably not the first deck at the King Ranch. But what we had done is we put together a work group that worked with ADNOC to talk about what the possibilities are for direct air capture and sequestration here in the United States versus Abu Dhabi. And the big focus was to try to help each of us to achieve the goals that we've set out. And ADNOC just set another goal for themselves to get to net zero, I think, by 2045. So they're on a mission. They have a goal, and we also do and we -- given the fact that we collaborated on making and building the what is now the largest -- and what was it, even at the time, the largest ultra-sour gas processing plant in the world. There were several companies that walked away from that they didn't want to try to attempt that. So we have a track record of working with ADNOC to do difficult things or to do things that are different. The sulfur recovery units in Al Hosn are serial numbers 1 through 4. So that's -- that was a bold step for us. And now we're taking this bold step to go into looking to help each other, and also to help our shareholders because the way we're doing this is in a way that it's not going to be a cost for us over time. It's going to be -- it's going to deliver returns and ADNOC is focused on that as well. So we have a very similar objectives around all of how we're doing this. And so the work team now will continue and start looking at sites here in the U.S. and the UAE and pick the one that gives us the best chance to ensure that right out of the gate, we're starting with a good project.

The next question comes from Roger Read with Wells Fargo.

I guess I'd like to follow up on some of the carbon capture. We saw a transaction occur, I guess, now about a month ago, on conventional sort of CO2 EOR. And I was wondering, as you look at your own operations there, anything you can look at or examining along those lines? Or have you had any inquiries from others about trying to expand the opportunity there?

I can't comment too much on what's happened. But I will say that there's probably not any carbon capture or CO2 EOR things that are happening in the U.S. or even worldwide that we don't follow very closely, one of which we had followed probably for a few decades or at least a couple of decades. But when we look at it, we -- and Richard can build on this. So we have now structured what we're doing so that we can focus on the things that we do best. And the things, as we've talked about in this call, the things that we do best are: one, understanding the subsurface. And since we have used CO2 for EOR for almost 50 years, what we're doing now is just a different way, a different kind of reservoir to put the CO2 into. So a different type of modeling, but all the same work goes into it and all the same the same techniques and approach go into looking at how we handle the CO2 and how we get it sequestered, whether it's in an EOR reservoir in the Permian or elsewhere or whether it's in a saline reservoir. So that part of it is our expertise. We don't really feel the need to own pipelines because pipeline returns are generally not the kind of returns that we can get with our dollars invested in either the upstream business or shale business or conventional. So what we want to do is make sure that our capital dollars are going to the things that we do best. We've partnered with midstream companies in the sequestration hubs that we've developed. And again -- but we do have as you mentioned and referred to significant infrastructure. We do have 2,500 miles of CO2 pipeline in the Permian. We're operating there 13 CO2 processing plants. And so we have the basis to do a lot of work and a lot of sequestration in the Permian, where I think the Permian as a whole, I think the capacity is estimated to be large enough to sequester all of the emissions from the United States for 28 years, and we have a big footprint in the Permian. There are multiple zones we can not only implement CO2 for EOR, but for a straight sequestration. So we're doing partnerships that give us the best return in collaborating because there's going to be a lot of capital required for these projects over time, and we don't want all of that capital coming from Oxy. Obviously, we want other companies doing what they do best to. Richard, do you want to comment on some of the sequestration hubs?

Sure. I mean -- yes, just build a minute. I think even especially in our Permian EOR or Permian position, we continue to work many carbon capture opportunities. We continue to think because of that legacy position we have, especially in the subsurface that that's going to present economic and real opportunity for us and emitters in terms of being able to capture and retire the CO2. In terms of the Gulf Coast, I know we talked about it before, but I want to reiterate, like Vicki said, be very focused on the sequestration of the subsurface piece of that. That's really as we learned where we could best add value, it's around that position, and we have our hubs that are going in the Gulf Coast. We've got several of our Class 6 wells that are permitted and moving well through the process, may have up to 6 by the end of the year. We're drilling strat wells really in every hub continuing to be prepared as we think these capture projects are going to be put together and come online over the next few years. So we really think we're positioned to be the low-cost kind of sequestration, certainly providing security around the CO2 because of our history. So great partnerships with midstream companies we've announced before, and they're an important piece, but we're really focused on that, both in the Permian and in the Gulf Coast around really developing that subsurface for sequestration.

The next question comes from Paul Cheng with Scotiabank.

Vicki and the team, with the improvement that you're seeing in DJ, what should we expect from the activity and the production trajectory for the next several years? I mean, in the past that I think with the limitation on the inventory or there maybe concern about regulatory, that production for you has been on the decline. Should we assume that the decline will continue, but at a slower pace or that you think you may be able to do better than that? That's the first question.

Okay. I'll turn that over to Richard. Richard's been actually looking at that more closely.

Sure. Yes. Let me just kind of walk you through where we were this year. Obviously, we were significantly underinvested in the last couple of years coming out of the downturn, really focusing capital on the shortest cycle. We really restored capital back to the Rockies this year back to more sustaining levels, but the teams continued to outperform. And so what really has happened this year is a shallower decline in the first half of the year. We had expected growth in the second half of the year, but the growth is actually a bit better. So if you look at kind of where we're at first half to second half, I think we're growing about 6,000 barrels a day. So the -- in terms of rigs, we're running capable -- been running 2, capable for 3. And we continue to work on these well improvements to see really how that asset and that production competes for capital in our portfolio going into next year. But I think really the -- sort of the capital that you're seeing deployed in the Rockies this year takes us from a decline into really a flat to moderate -- low-end growth.

Rich, can we assume that that's the minimum that you will be able to do for the next several years that led to maybe modest growth?

Look, the teams have continued -- we challenge everybody, but I think the Rockies team has really done a great job on this. Getting upfront in terms of land development, permits, really getting the midstream position in place to be able to do more. But again, it needs to fit our capital allocation. So they do high returns even at lower gas prices. These are very competitive returns. I would call them a bit longer cycle than the, say, the Delaware in Texas, but they also have a bit lower decline. And so for us, they fit really well. We'll have capability to do more, but it really needs to fit the sort of cash flow outcome that the company needs as we put capital together for next year. But we can do more as that fits.

The next question comes from Devin McDermott from Morgan Stanley.

So I wanted to go back to Stratos, the first DAC plant in Texas. You've made some progress in contracting some of the offtake there. I was wondering if you could just talk at a higher level on the demand that you're seeing for offtake from that DAC facility? And then I think signing offtake was one of the key factors driving some of the ranges in capital spending for lower carbon ventures this year. Could you just talk about where we're trending within that range as well?

Yes, great. I'll start with the CDR sales. I think as we've continue to talk about, we really believe in the market and believe that really the formation and sales are following kind of our expectations. I mean, clearly pleased with strategic, strong strategic customers like A&A that recognize really the fit of our product, which is a CDR into a larger aviation decarbonization. So while there -- we think about broadly sustainable aviation fuels, we feel like CDRs fit well into that market. So if you look at some of the equivalents on probably a better marked market in terms of sustainable aviation fuels, those may range $800 to $1,000 a ton we believe we're going to settle into that market well. Really, the key for us, though, as we continue to talk, is driving the innovation and cost down in DAC. And so we remain focused not only the construction parts going on in Permian with Stratos, but also in our King Ranch development, but very pleased with the progress carbon engineering makes with their innovation center. So I didn't want to talk about just the market because we do believe that cost down is important for us to make this affordable long term. The other mark I'll give you, just in terms of thinking about kind of sales and how the CDRs fit on the price ranges, I think in April European Parliament put together some things around requiring 2% SAF mix starting in 2025 and some of those penalties are $550 per ton of CO2. So when you look at how we can compete directly offset that at a lower cost. We think that's another mark that really helps us think about how we can be competitive.

Great. And then just on the lower carbon spending in your plan this year, I think the offtake and the ability to finance off balance sheet was one of the swing factors. Can you just give us an update on that process as well?

Yes. No, I think -- look, we remain optimistic that we're going to have good partners as we think about financing this long term. We've been strong in our ability to be able to carry the near term, but we understand longer term that we need financial partners that come into this with us, and we continue to make progress. Just to talk about the capital, we've stayed with the range $200 million to $600 million for the year. And really, that reflects that room to bring in that capital partnership by the end of the year.

Yes. And I would say, Devin, I appreciate your interest and we will have a bit more of an update in November. I want to give anybody to thinking it's some sort of major announcement, it's not. It's just an update just like what Richard gave now because things are continuing to change with respect to demand for CDRs and that sort of thing. So we'll give you a little more of that in November.

Yes. I think construction progress, I should say, we're about 23%, I think, to date. So we'll have more construction progress. We think we can point more to the market. And just kind of follow-up on that deep dive we had last year kind of giving some updates on how these pieces come together.

[Operator Instructions] The next comes from Scott Gruber with Citigroup.

Yes. Just had one question, just following up on that last point. The ADNOC MOU is quite encouraging. But whether it's ADNOC or another partner? In terms of just thinking about making that equity investment in DAC, do the partners that you're talking with, do they want to see the learnings from Stratos manifest into lower capital and operating costs, DAC 2 or DAC 3 to pull the trigger on an investment? Or do you sense that just showcasing progress in constructing Stratos and getting it up and running would be sufficient to attract equity funding into the program?

I would say with ADNOC, they know our track record of building major projects and they know Ken Dillon well, who's actually manages our major projects. So they've seen us and how we not only -- we're innovative in how we built Al Hosn, but we were also innovative in this just recent expansion to expand the plant by almost 50% with probably spend way under 10% is -- was phenomenal. And so I think that ADNOC will be prepared to move forward with us sooner than waiting on what happens with Stratos. I think they all understand that technologies go through a cost down. There's never been a technology that's worked and been adopted in large way without having gone through the same kind of thing that we'll go through with our direct air capture.

Yes. And the only thing I would add, I mean, there definitely is different capital, I think as we're able to move down that cost down over the next decade. We really like to partner with strategics like ADNOC or others that can be a part of not only the near term, but the long term. But obviously, we want to get the right value and set up the right economics for both parties as we bring them in. And so I think, of course, long term, as we bring costs down, the market forms, we expect that to open really capital, and that's a big part of our ability to scale development. And so to answer your question, yes, I do think that changes -- presents more opportunities over time.

Yes. One final comment on it is, partnering with ADNOC, we know their capabilities and expertise, too. So we know what they bring to the table. And so that's the other exciting aspect of this is having their knowledge and their experience, their expertise combined with ours, to do whichever we do or a combination of both the CCUS and the direct air capture.

The next question comes from David Deckelbaum with TD Cowen.

I'm going to try to ask one perfect question. I was curious, you mentioned before, obviously, with the curve where it is now, you need to see it a bit higher to start prosecuting more preferred redemptions. Does the cash flow priority change given the fact that it's harder to achieve that milestone in the coming quarters? Or should we expect sort of a similar pace or distribution or free cash via buybacks sort of irrespective of where the curve is in the back half of this year? And does it change how you think about capital allocation, perhaps into next year relative to sustaining capital versus growth capital?

I would say that we're not going to execute a large growth program in our upstream oil and gas business. So -- but I will say that our intent is to keep a moderate capital spend, what we consider to be something similar to the activity level that we have on a whole year basis, not the second half, take the second half of this year and project it into next year is what our oil and gas activity level would be. But what we want to do is we just want a program that delivers the best returns at present value. So that doesn't mean that we're going to take our capital framework right now and dramatically change it. Share repurchases is a part of that. And that's -- it's an important part of that. And what we do will depend on the macro. But from the -- what -- I would say what we see with the macro now, I wouldn't discount our ability to do both, to repurchase common shares whilst also being able to redeem some of the preferred next year because I do see a better price environment, I believe, than what some realize it's going to be. So I think there are a lot of reasons pointing to a pretty good environment. So I wouldn't discount it yet. I do believe that we'll have the opportunity to do both, but share repurchases will always be a part of our framework.

The other thing I'll add, David, too, is in 2023, because our share repurchase program is thus far, far more ratable in our concentration and purchases last year. We're creating a foundation for 2024. We don't have as many slugs to overcome with us that necessitate spikes in oil prices or whatever to get there. So we are laying the groundwork for next year even as we continue to buy share repurchases this year, whether or not we're retiring preferred along with it or not.

In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.

I would just like to say thank you all for joining us, and have a great day.