Occidental Petroleum Corp (OXY) — Q2 2023 Earnings Call Transcript

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 three things I'd like to drive home today. First, our portfolio of assets continues 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 that drive even better shareholder returns. I'll begin with the portfolio. We have the highest quality and most complementary assets that Oxy has 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. Sixty percent of our oil and gas production comes from shale reservoirs and forty percent from conventional. More than eighty percent of our production is in the United States. The international oil and gas assets that we operate are in only three countries: Oman, Abu Dhabi, and Algeria. Our worldwide full year 2023 production mix is expected to be approximately fifty-three percent oil, twenty-two percent NGLs, and twenty-five percent gas, with seventy percent of the gas in the United States. Our conventional oil and gas assets, along with OxyChem, provide 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 compared to the cash flow generated by the previous portfolio 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 thirty-two percent faster on a foot per day basis than they did in the first quarter. The diligent work set several new Oxy records, including the company-wide record of drilling over 10,400 feet of lateral in only twenty-four hours. Just ten years ago, it took the industry an average of fifteen days to drill 10,400 feet. Our Permian production delivered higher operability and better-than-expected new well performance, particularly in our two 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 twelve hours for a total of forty hours and forty-nine minutes. Four years ago, the same job would have taken about eighty-four hours. Forty 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 costs and reduced 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 two 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 with a very small incremental capital investment. In Oman Block 65, we drilled a near-field exploration well, which delivered 6,000 BOE per day in 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 a 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 balances 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 improve. In the Permian, we have improved well productivity in seven of the last eight years. 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 twenty percent lower costs. The improved well design has resulted in about twenty-five percent improvement in single well twelve-month cumulative volumes over the last five years. 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. The key for our U.S. organic reserves replacement ratio last year was a remarkable 212%. 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 ten of the last twelve years, we have replaced 150% to 230% of our annual production, with the only exceptions being in 2015 during the price downturn and 2020 during the 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, but 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 support the 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 preferred equity. To date, we've redeemed approximately $1.2 billion of preferred equity.

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. The 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 enabled 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 LCV's 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 mainly driven by reductions in commodity prices and fewer barrels in shipment over the 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 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 to 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 for the year. Rockies outperformance serves as the largest catalyst for 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 the 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 are 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, 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 the Gulf of Mexico, Permian, and Rockies, with latter two businesses also benefiting from nonrecurring production events. We have better anticipated wells and time-to-market momentum year-to-date, which we expect to benefit from in the second half of the year. The third quarter will be the only quarter in the year where production averages below 1.2 million BOE per day. Reduced production is mainly driven by the previously mentioned weather contingency in the Gulf of Mexico. The decrease in third quarter production will likely result in total company production being lower in the second half of the year 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 two 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 fifty-three percent, largely due to improved Gulf of Mexico production. 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 pre-tax income midpoint of $1.5 billion, which will represent our third-highest pre-tax 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 due to 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 by 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. 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 settlement. While this settlement will drive our reported overhead down, our full year guidance on overhead expense on an adjusted basis remains unchanged. Turning now to shareholder returns. As Vicki mentioned, we've 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 redeemed approximately $1.2 billion or twelve percent of preferred equity that was outstanding at the beginning of the year with ten percent premium payments to the preferred equity holders of approximately $117 million. Preferred equity redemptions to date have resulted in the elimination of over $93 million of annual preferred dividends. As of August 2, rolling twelve-month common shareholder distributions totaled $4.08 per share. Due primarily to the concentration of share repurchases 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 be heavily 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 return program, including our $3 billion share purchase program. Our basic common share count is at its 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 in a return to investment-grade status when Fitch ratings upgraded Oxy in May. We believe that our investment-grade credit rating reflects our exceptional operations, diversified high-quality asset portfolio, and our commitment to pay down debt as it matures. Our second quarter results and our full year guidance demonstrate solid progression toward another strong year for Oxy. We look forward to reporting on additional progress as the year advances.

Thank you, Rob. Before closing today, we'd like to briefly mention two 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 with a more comprehensive update toward the end of this year. With that, we will now open the call for questions.

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, quite frankly, a 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 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 hundred wells, and maybe twenty-five percent of them would be really good and seventy-five percent 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. I would say that in the past two to three 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. So where we are today is, I've now asked the teams to stop talking about it. We were 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 and to our shareholders to keep that proprietary because this is something that's pretty phenomenal, I think. Now we're taking this, and we're going to apply it to the Powder River Basin. We've also taken learnings from the team in the DJ and moved those through the Permian. 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. I think Richard will say a little bit more about that later, but the Southern Powder River is—where we are seeing good results. Our appraisal team is beginning to work in the northern part of the Powder River. We're going to use the same methodology for both shales and conventional reservoirs to generate better outcomes. Our teams have done amazing things in terms of their developments.

I've got a very quick follow-up, and it’s 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? 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 Texas and Delaware are really top tier. 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 thought they were, I believed for a while better than Southeast New Mexico. I think I mentioned 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 both Southeast New Mexico and Texas Delaware are incredibly important to us. They are very high quality, and they are both a part of our program going forward. Richard, did you have 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 is that we talked about knowing we would decline through the first half of the year and then grow. If you see our guidance for the third quarter and then implied guidance for the fourth quarter, you'll note that the first half was not just better but the second half is also better. While the new wells are core, we need to think about capital deployment and how to create efficiency, but I’d also like to recognize all the team that works on our base production. The Rockies is a great example of being able to rethink our surface infrastructure; they've been able to lead the industry, I think, in some of these tankless designs but have migrated to more efficient bulk and test. They've been able to think about artificial lift earlier, utilizing gas lift upon completion. A lot of that beyond creating the most EUR per dollar spent is really helping our production.

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

Yes. Just to start off on the return of capital. Just curious about 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. Certainly, at $75 and above, we've got the cash to do both. What we feel like with our current shareholder framework is that share repurchases are a important part of that. Because what we're really trying to do is create value per share for our investors. To create value per share, it not only means that we need to grow production a bit but, again, that's with the cash flow growth being essential. This year, we will see incremental earnings growth from our incremental volumes, but also developing our reserves at a lower cost, which we've been discussing. What the teams are doing is so vital—it’s about building reserves, replacing production, and finally buying back shares, especially given that we feel we're very undervalued right now.

I'll just add that part of the challenge we have is that our program last year was heavily back-end weighted. We did $2.4 billion of share repurchases concentrated in the second half of the year, with $1.8 billion of that in the third quarter. So it’s the pace at which we were able to retire shares last year, matched with the commodity prices we have this year that is making it difficult to stay with the $4 per share target consistently.

And then the follow-up is congrats on getting the Al Hosn gas expansion this year. Just love any perspective 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 1.45 Bcf a day, had very little capital. It is definitely a good project for us. Just having gotten that back online, we expect that the production outlook is good for the remainder of this year from Al Hosn, and also the fact that in Oman, we were able to get an exploration well that was record-setting for us online to production in less than a month was another good sign that we have 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. We have set production records there, and that's a field that's been in operation for over forty years, so we're still finding opportunities.

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 current opportunities today in the Gulf? And could we see any notable change in activity there in the coming quarters?

I would say that 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 there, and the anticipation of artificial intelligence and advanced data analytics, will be game changers for the Gulf of Mexico. 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 looking forward over the next three to five 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 in your discussions, have your thoughts on space or completion design changed going forward? I know you’ve been ramping that up. And I was wondering if there's any thoughts regarding spacing or completion design changes?

Yes. Great. We’re very excited about the DJ; the new well performance and productivity in the base have been strong. But I would say consistent with our approach across our reservoir positions, it really starts with the challenge in the subsurface regarding what you described—spacing and how many wells per DSU. The teams continue to look at those opportunities. Just moving from eighteen wells to eight to twelve wells per section allows us to deliver the same EUR at less cost. We have improved, reaching fifteen hundred pounds per foot, which is up about thirty percent from our prior designs. As we think about spacing, the thing I would say is not every drill spacing unit is the same. The geology changes, and the development sequencing changes. So there’ll be areas where that may differ. I think just to contrast a little bit, we highlighted the performing DSUs in the Delaware Basin; those are opportunities where we added wells per section. We were able to do so by examining the unique attributes of each unit. The operations team has put together a holistic design that allows those wells to flow optimally.

You talked extensively about improving well productivity, and I know a lot of companies have mentioned service costs softening here. Looks like 2024 consensus estimates anticipate you'll spend about four percent more next year than this year to keep production flat at the current level. I know it's early to give guidance for '24, but just want to get your view on that outlook.

What we're seeing is some things starting to plateau in terms of cost. We're seeing labor being still a bit tight. But there's a challenge around labor, not seeing as many people wanting to change jobs. The big challenge is to get truckers to drive trucks and people to do the welding and those important field jobs. While we do not expect to see much reduction in service company costs, we do not expect any significant increase next year either.

We’re pleased with the efficiency of our operations. The rigs we've added over the last year and a half have highlighted some individual goals, but productivity continues to improve through reduced nonproductive time. If we look into next year, that's going to continue to be our challenge. We hope there's some pricing relief that can benefit both operators and service companies.

I just wanted to add that we encourage our coverage group not to rely too much on consensus for the future. As you know, the further out it goes, the more sale data can be included. So just continue to have conversations with us, and we'll guide at the appropriate time.

Got you. I guess just summing all that up, though, based on those numbers, it 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 yet—our teams are still generating more barrels. If you look at the graphs, our teams are getting more production from the wells for that same or lower cost. This year, we have been able to do both. We are increasing efficiencies of execution while also getting more recovery out of the wells. So I don't think we’ll need to spend more capital just to stay flat. And again, I think we still have the lowest capital intensity on a per barrel basis in the industry.

Appreciate the detail on that. One follow-up on your agreement with ADNOC. Does that cover Stratos? What kind of capital is the company looking to spend with you at this point?

It doesn't cover Stratos, but it does cover other endeavors. What we have done is structure our discussions with ADNOC to look at possibilities for direct air capture and sequestration here in the U.S. and Abu Dhabi. Our collaboration aims to achieve our respective net-zero goals. We have a track record of working with ADNOC to do challenging projects, and we are taking bold steps here together to drive returns both for ADNOC and ourselves.

I'd like to follow up on carbon capture. We saw a transaction occur about a month ago, regarding conventional CO2 EOR. As you look at your own operations there, is there anything you're considering or examining along those lines? Or have you heard inquiries from others?

I can't comment too much on what has happened, but I'll say that we follow carbon capture activities closely, both in the U.S. and worldwide. Since we've been using CO2 for EOR for almost fifty years, what we are doing now is just a different way to sequester CO2. However, we don't feel the need to own pipelines because the returns typically do not meet our expectations. We want our capital dollars allocated to things we do best.

Yes, we continue to work on many carbon capture opportunities. Because of our legacy position, especially in the subsurface, I think that presents economic and real opportunities for us in working with emitters to capture and retire CO2. In terms of the Gulf Coast, we reiterate the need to focus on sequestration in subsurface areas. We believe our historical operations give us the advantage in that space.

With the improvement you're seeing in DJ, what should we expect from the activity and production trajectory for the next several years? Are we to assume the decline will continue, but at a slower pace, or do you believe you may be able to do better than that?

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

Yes. Let me walk you through where we were this year. We were significantly under-invested in the last couple of years coming out of the downturn, with capital primarily focused on the shortest cycles. This year, we restored capital back to the Rockies to sustaining levels, but the teams have also continued to outperform. So what has happened this year is a shallower decline in the first half. We had expected growth in the second half of the year, but the growth is actually a bit better. We are running two rigs capable for three and working on well improvements to see how the asset holds up over the next year. This year’s capital deployment in the Rockies has shifted us from decline toward flat to low-end growth.

I wanted to go back to Stratos, the first DAC plant in Texas. You've made progress in contracting some of the off-take there. I was wondering if you could talk at a higher level on the demand for off-take from that DAC facility? I think signing off-take was key in your capital spending ranges for lower carbon ventures this year. Could you just touch on where we are trending within those capital ranges?

Yes, as we have discussed, we believe in the market, and our expectations regarding formation and sales are falling in line with our projections. We’re pleased with securing strong strategic customers like A&A that recognize how our product, which is CDR, fits into broader sustainable aviation fuel goals. We expect to settle into the medium between $800 to $1,000 per ton for CDRs. Our priority will be on innovation and cost reduction in our direct air capture systems. Additionally, we've made substantial progress in the construction of Stratos.

Yes. We will provide more updates on this in November. To clarify, we're looking at ongoing markets for CDRs and construction developments, with the progress ongoing and evolving.

Just had one question, following up on that last point. The ADNOC MOU is quite encouraging. But whether it’s ADNOC or another partner, in terms of making that equity investment in DAC, do the partners you talk to want to see learnings from Stratos manifest into lower capital and operating costs for DAC 2 or DAC 3 to pull the trigger on an investment? Or do you sense that showcasing progress in constructing Stratos will 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 manages our major projects. They’ve seen us innovate how we built Al Hosn and how we managed projects efficiently, so I believe ADNOC will be prepared to move forward with us sooner than waiting for Stratos. They understand that technologies to cost down will take time, which is a common trajectory in major projects.

Yes. There are different factors driving capital needs. As we reduce costs over the following decade, we believe that forming strong partnerships, whether with ADNOC or others, will enhance not only the near term but also the long term. This allows us to build strong relationships while fostering confidence in cost reductions as time goes on.

One final comment on partnering with ADNOC is that we know their capabilities, and expertise is compelling. Their experience combined with ours provides an exciting aspect as we explore both CCUS and direct air capture opportunities.

I'm curious; you mentioned before with the curve where it is now that you need to see a bit higher to start managing more preferred redemptions. Does that change your cash flow priority given it’s harder to achieve that milestone in the coming quarters? Should we expect a similar pace of distribution or free cash via buybacks 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. Our intent is to maintain moderate capital spending levels similar to this year's overall activity level, not the second half specifically. We want to deliver the best returns at present value, which will include share repurchases as part of our strategy. What we see with the macro environment leads me to believe we can execute both share repurchases as well as redeem some of the preferred equity next year, as I foresee a stronger price environment.

In 2023, because of our share repurchase program being more evenly distributed, we're creating a foundation for 2024. We don't have as many large slogs to overcome. We're laying groundwork for next year while still buying shares this year, regardless of the number of preferred shares we retire.

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