Occidental Petroleum Corporation (NYSE:OXY) Q3 2025 Earnings Call Transcript

Occidental Petroleum Corporation (NYSE:OXY) Q3 2025 Earnings Call Transcript November 11, 2025

Operator: Good afternoon, and welcome to Occidental’s Third Quarter 2025 Earnings Conference Call. [Operator Instructions] Please note that today’s event is being recorded. I would now like to turn the conference over to Jordan Tanner, Vice President of Investor Relations. Please go ahead.

Jordan Tanner: Thank you, Rocco. Good afternoon, everyone, and thank you for participating in Occidental’s Third Quarter 2025 Earnings Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Sunil Mathew, Senior Vice President and Chief Financial Officer; Richard Jackson, Senior Vice President and Chief Operating Officer; and Ken Dillon, Senior Vice President and President, International Oil and Gas Operations. 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 Hollub: Thank you, Jordan, and good afternoon, everyone. I want to take a moment to recognize Veterans Day and express our deep gratitude to all veterans and their families for their service. Today, I will address our recently announced sale of OxyChem, outline the strategic rationale and highlight our third quarter performance. Richard will provide details on our oil and gas operations, and Sunil will review our third quarter financials, fourth quarter guidance and considerations for the year ahead. The sale of OxyChem is a pivotal step in our transformation. The decision was driven by the scale, quality and diversity of the oil and gas portfolio we have built over the last decade. Since 2015, we have more than doubled our total resource potential and our production, going from total resource of 8 billion barrels of oil equivalent to 16.5 billion barrels of oil equivalent and from production of 650,000 BOE per day to over 1.4 million BOE per day.

We now have a higher-quality portfolio with Oxy’s lowest-ever geopolitical risk as we have shifted the percentage of our oil and gas production from 50% domestic to 83% domestic. And our portfolio has a development runway of 30-plus years that includes high-return, short-cycle, higher-decline unconventional assets complemented by solid return, lower-decline mid-cycle development opportunities in our conventional oil and gas assets. Our substantial oil and gas runway, along with our demonstrated expertise in maximizing resource recovery, created the foundation for accelerating value to our shareholders through the divestiture of OxyChem. The proceeds will be used to immediately strengthen our balance sheet, allowing us to significantly deleverage and achieve our principal debt target of less than $15 billion.

This will reinforce our financial resilience and agility to navigate changing market conditions. With greater financial flexibility, we can broaden our return of capital program and accelerate shareholder returns. This will enhance our approach to delivering value to our shareholders by increasing cash returns and continuing to rebalance enterprise value through net debt reduction. Our strengthened financial foundation will enable us to accelerate the development of our industry-leading oil and gas portfolio by focusing capital on our Permian unconventional assets, including unconventional CO2 floods, along with our Gulf of America waterfloods and in the future, our Baqiyah gas and condensate discovery in Oman. We’re excited about all the opportunities ahead to apply our subsurface expertise for greater resource recovery and the opportunities to advance our various low-decline enhanced oil recovery projects, particularly our CO2 EOR projects.

Now turning to the third quarter. Our teams delivered another strong quarter of operational performance, generating $3.2 billion in operating cash flow and $1.5 billion in free cash flow before working capital. Notably, we exceeded last year’s third-quarter operating cash flow despite WTI prices that were more than $10 per barrel lower in the third quarter of this year. Our team’s continued focus on cost management and efficiency improvements also led to our lowest quarterly lease operating expense per barrel across our full oil and gas segment since 2021. This ongoing improvement in portfolio and operational performance underscores the quality of our resources and the exceptional caliber of our teams who continue to bring forward value by delivering more with less.

In the third quarter, our oil and gas business produced approximately 1.47 million barrels of oil equivalent per day, exceeding the high end of our guidance range. The Permian Basin contributed 800,000 BOE per day, which is the highest quarterly Permian production in Oxy’s history. The Rockies also posted outstanding results, thanks to strong new well performance and stable base operations. Additionally, our Gulf of America assets outperformed the high end of guidance, benefiting from favorable weather and achieving the highest uptime in our operating history. Our Midstream and Marketing segment delivered another incredible quarter, generating positive adjusted earnings and surpassing the high end of guidance. Our teams expertly navigated market volatility to maximize margins through strategic gas marketing, helping to offset challenging gas price realizations.

Higher sulfur prices in Al Hosn further contributed to the quarter’s results. As shown in our third quarter results, we remain focused on generating free cash flow at lower oil prices and maintaining flexibility in our capital and development programs to support near- and long-term value creation. Richard will now provide more details on our third quarter operational highlights and how we are positioned to generate stronger returns and higher free cash flow.

Richard Jackson: Thank you, Vicki. I appreciate the opportunity to share the progress we are making in our operations and how we are positioning our plans going into 2026. In all parts of our oil and gas business, we are making significant advancements through a focus on 3 key areas: resource improvement, cost efficiency and operating ability to generate free cash flow across a range of oil price scenarios. Today, I will focus on our Permian operations, where there have been several meaningful updates across these 3 areas. I look forward to sharing more from our other teams in future calls. First, let me begin by highlighting our strong third quarter results. As Vicki noted, domestic production exceeded guidance with strong contributions from all business units in the Permian, Rockies and Gulf of America.

This strong performance and record results were achieved while sustaining our outlook for lower capital and improved operating costs for the year. Compared to our original 2025 guidance, we have reduced capital expenditures by $300 million and operating costs by $170 million. We appreciate our team’s continued efforts to exceed expectations. Importantly, this performance is part of our continued track record of cost efficiency. We recently highlighted that since 2023, we have realized $2 billion in annualized cost savings across our U.S. onshore operations, driven by continuous operational improvements in drilling, completions and operating expense categories as well as a value-focused supply chain management approach. We are seeing similar improvements across all of our operating teams and look forward to these efficiencies continuing into 2026.

Building more on Vicki’s introductory comments, we have made important progress in our organic oil and gas resource improvement across the portfolio. Today, I will focus on the Permian as it plays an essential role in our near- and long-term results. We have recently expanded our Permian resource base by 2.5 billion BOE, which now represents approximately 70% of Oxy’s total resources of approximately 16.5 billion BOE. We achieved this organic resource expansion through subsurface characterization and the application of advanced recovery and technologies. Our deep Permian resource is both low cost and provides operational flexibility to support free cash flow across a wide range of oil price scenarios. When combined with our ongoing cost efficiencies and technical recovery advancement, this places the Permian as a core value driver for Oxy’s future.

To start, in the Delaware Basin, we continue to be a leader in new well performance across both our primary and secondary benches. Importantly, our secondary bench wells outperformed the industry average by 10% when compared to all benches, primary and secondary in the basin. In addition to improving productivity, these secondary benches also enable us to efficiently utilize existing infrastructure that was built to support our primary development. As a result, we have extended our resources through increased secondary bench development while lowering our overall development costs, leading to a 16% lower capital intensity since 2022. Additionally, over the last few years, we have significantly transformed our position and performance in the Midland Basin.

Today, these development projects are incredibly competitive in our Oxy portfolio. This process began with a basin-wide subsurface characterization initiative and targeted development program to more fully understand the resource potential in the basin. We then strengthened our acreage position and achieved the scale needed for operational efficiencies through the CrownRock acquisition. Today, the combined Oxy and legacy CrownRock teams are delivering industry-leading well costs and performance, driven by both continued operational improvements and refined subsurface designs. Since 2023, our new wells have shown a 22% increase in 6-month cumulative oil production per 1,000 feet, while the industry average has declined about 5% over the same period.

We have also reduced well costs by 38% since 2023. These step changes have created an expanded deep bench opportunity, allowing us to organically add top-tier Barnett resources across 115,000 acres in our Midland and Central Basin Platform operating areas. Again, we highlight that our new well performance in the Barnett is outperforming the industry average by 18% since 2020. Another resource opportunity and key differentiator for Oxy is the expansion of enhanced oil recovery into our unconventional shale. As a leader in conventional CO2 EOR, we are leveraging our decades-long investment and expertise into these assets. Since 2017, we have advanced unconventional EOR in our Permian, U.S. Permian and Rockies business units, completing multiple demonstrations where we have achieved positive and consistent results.

These projects have delivered over 45% oil uplift, but we believe with continued optimization, our commercial projects have the capability to deliver up to 100% production uplift. We are now moving into commercial development with 3 initial projects and a current pipeline of 30 more ready for development. These mid-cycle projects offer low decline rates and competitive returns. Our unique and sizable Permian Basin CO2 infrastructure gives us an advantage as we scale these developments over time. Today, this represents a resource opportunity of over 2 billion BOE. We also continue to advance our existing conventional EOR assets with approximately 2 billion BOEs of undeveloped resources with low development costs, these mid-cycle projects are also meaningful as part of our future resources.

Recent improvements in cost structure, including $80 million of our 2025 domestic operating cost reductions continue to improve the returns and investment priority within our portfolio. Beyond CO2 EOR, we are progressing a suite of complementary recovery technologies, including infill drilling, precision well placement and spacing, next-generation frac and other methods of EOR. We believe our ability to organically expand our low-cost resource base through subsurface characterization, continued cost efficiency and advanced recovery technologies give us a competitive advantage to deliver long-term value. As we look ahead to 2026, we continue to actively manage our operational scenarios for a disciplined approach for resilient free cash flow even if in challenging oil price environment.

Our approach begins with a focus on operational and cost efficiency over activity reductions to preserve future free cash flow and to maintain optimized activity across our assets. A key part of this approach is working closely with our service company partners to capture supply chain savings, improving value for both parties. Beyond that, we selectively defer multiyear facilities and construction projects, allowing us to invest opportunistically in these projects when conditions are more favorable. We also regularly review and optimize our operating expense activities to enable us to scale and time activities for maximum free cash flow. Finally, we evaluate capital and development activity adjustments, always with a focus on achieving the most efficient capital to cash flow outcome.

At much lower oil prices, capital flexibility becomes critical, and we remain committed to investing wisely, preserving optionality and delivering value through efficient execution. As we enter 2026, we are targeting a $55 to $60 WTI plan with flexibility to adapt to market conditions while continuing to improve cost efficiency to deliver our free cash flow needs without impacting operational performance. Looking ahead, we have a deep portfolio of short-cycle, high-return and mid-cycle low-decline assets that can deliver strong cash flow. We are focused on sustaining momentum by driving cost efficiency, advancing recovery technologies and optimizing our operations. Lastly, I’d like to thank all of our teams for their continued performance and especially safety as we look to end the year strong.

I also look forward to working closer with many of you for the first time or again in my new role. Thank you for your time today, and I’ll now turn the call over to Sunil for the financial discussion.

Sunil Mathew: Thank you, Richard. In the third quarter, we generated a reported profit of $0.65 per diluted share. Strong operational performance and a continued focus on capital efficiency enabled us to generate approximately $1.5 billion in free cash flow before working capital. We had a negative working capital change, primarily driven by the timing of semiannual interest payments on our debt and payments within our Oil and Gas segment. During the quarter, we repaid $1.3 billion of debt, bringing our total year-to-date debt repayment to $3.6 billion and reducing Occidental’s principal debt balance to $20.8 billion. Our strong financial performance can largely be attributed to higher volumes across our U.S. portfolio, which more than offset slightly lower-than-expected production from our international assets.

New well and base production outperformance in the Permian and Rockies as well as higher uptime and favorable weather in the Gulf of America enabled us to exceed the high end of guidance across all of our domestic oil and gas assets. This production outperformance and the continued focus on delivering operational cost efficiencies led to lower domestic lease operating expenses in the quarter, notably outperforming guidance at $8.11 per BOE. Part of the outperformance also reflected the timing of certain offshore production engineering activities, which shifted into the fourth quarter. In the Midstream and Marketing segment, we continue to capture value through optimizing our gas marketing positions out of the Permian Basin and higher sulfur pricing in Al Hosn.

Both were significant catalysts in the segment, generating positive earnings on an adjusted basis of $153 million, above the midpoint of guidance. Looking ahead, we are increasing our full year guidance for our Oil and Gas and Midstream and Marketing segments as a result of our strong third quarter outperformance and improved expectations for the fourth quarter. In Oil and Gas, we are raising our fourth quarter total company production guidance from last quarter’s implied guidance to a midpoint of 1.46 million BOE per day. This is driven by the expectation for continued strong performance across all 3 domestic assets, which should more than offset impacts from a scheduled turnaround at Al Hosn also in the fourth quarter. Other Midstream and Marketing pretax income guidance assumes that our teams will capture gas marketing optimization benefits from the wider Permian to Gulf Coast spread observed already in the fourth quarter.

We expect full year pretax income from the segment to come in approximately $400 million above our original guidance, largely due to those gas marketing opportunities and stronger-than-anticipated sulfur pricing from Al Hosn. Due to continued softness in the global chlorovinyl market, our third quarter OxyChem pretax income came in below guidance at $197 million. We are guiding to $140 million for the next full quarter. Beginning in the fourth quarter, OxyChem will be classified as discontinued operations. We are in the process of evaluating the potential impact of OxyChem’s classification on our fourth quarter adjusted effective tax rate, and we will provide a further update early next year. Total company capital spend, net of noncontrolling interest of approximately $1.7 billion was in line with our expectations for the third quarter, and we expect to remain within our previously guided range for 2025 capital.

As Vicki shared, the OxyChem transaction marks a significant milestone for our company as it will strengthen our financial position and enhance our ability to return capital to our shareholders. The all-cash nature of this transaction will enable us to accelerate our debt reduction efforts and achieve our post-CrownRock principal debt target of less than $15 billion. Of the roughly $8 billion in transaction net proceeds, we plan to use approximately $6.5 billion to reduce debt. Our initial focus is on the $4 billion of debt maturing in the next 3 years. This includes $1.3 billion of term loans maturing in 2026, which we can call at par and for the remaining $2.7 billion, we may largely use make-whole provisions to ensure certainty. Beyond that, we will be opportunistic, taking into consideration redemption prices and the impact on our maturity profile.

This will meaningfully improve our credit metrics and is expected to lower our annual interest expense by more than $350 million while providing a very manageable near-term debt maturity schedule. The remaining $1.5 billion in net proceeds will go to cash on the balance sheet. By significantly lowering our debt burden and building cash on hand, we will create a stronger, more resilient balance sheet. With the achievement of our post-CrownRock principal debt target, Oxy will be positioned to broaden our return of capital program and adopt a more flexible framework for delivering value to our shareholders. We will be opportunistic with the share repurchase program. Our decisions and priorities will be driven by a range of factors, including the macro conditions, commodity prices, market valuation relative to Oxy’s intrinsic value, cash on the balance sheet and the timeline to August 2029.

We plan to resume the redemption of the preferred in August 2029 when the preferred equity becomes callable with a lower redemption premium and does not have the $4 per share return of capital trigger. Now I would like to share how we are approaching our capital program for 2026. Last quarter, we discussed the potential to allocate capital to mid-cycle conventional oil assets. We are planning to increase investment in the Gulf of America waterflood projects and in Oman, given both projects’ high oil weighting and favorable base decline rates, combined with the enhanced economics in Oman following our Mukhaizna contract extension. Approximately an additional $250 million could be allocated to these areas as capital rolls off in our LCV portfolio.

Considering the recent commodity price volatility and oil market outlook, we are evaluating multiple capital scenarios across our U.S. onshore portfolio. With the OxyChem sale, our U.S. onshore capital will comprise an even greater proportion of the total company investment program, which provides flexibility should the macro environment deteriorate. As Richard mentioned, we have an incredible runway of high-quality oil and gas opportunities and sustained momentum in delivering value through greater capital efficiency. We plan to reallocate up to $400 million to these short-cycle, high-return projects, primarily in the Permian. Any additional allocation of capital next year will be undertaken in a thoughtful manner with an eye to the oil market, given oversupply concerns.

The quantum of that reallocation will depend on the macroeconomic environment, and we plan to share more on our 2026 capital budget during our fourth quarter call, pending Board approval. I will now turn the call over to Vicki for closing remarks.

Vicki Hollub: Thank you, Sunil. As we highlighted, the OxyChem sale represents more than just a business decision. It marks the final major milestone in the strategic transformation that we’ve been pursuing for years. With this step, we are accelerating opportunities to extend our advantaged low-cost resource position and leveraging integrated technologies to deliver differentiated recovery and superior value. We are confident that these actions will further strengthen our competitive position. With that, we’ll now open the call for questions. And as Jordan mentioned, Ken Dillon is joining us today for the Q&A session.

Q&A Session

Operator: [Operator Instructions] And today’s first question comes from Doug Leggate with Wolfe Research.

Douglas George Blyth Leggate: Vicki, maybe the first question is for Sunil, actually. It’s on the capital guidance that you just talked about there, the soft outlook. If I’m doing the math correctly, so you dropped about $300 million from the beginning of this year, so you $7.2 billion. But $900 million was chemicals, as I understand it for next year. And I believe this year was $450 million on DAC. So that’s about $1.35 billion. I’m trying to kind of get to the range for next year. So if you add back the $650 million you talked about, are we in the ballpark to think that spending next year should be down about $700 million on your — based on your remarks, Sunil?

Sunil Mathew: Yes. So Doug, you’re right on the way you’re approaching it. Like you said, midpoint for CapEx guidance for this year is $7.2 billion. Chemicals was $900 million. So you back out that, you’re at $6.3 billion. Like I mentioned, we are going to increase CapEx in the Gulf of America waterflood projects and Oman, which is around $250 million, which will be largely offset by the roll-off of capital in our low-carbon venture portfolio. So you’re back to the $6.3 billion. And with respect to U.S. onshore, like I mentioned in my prepared remarks, we are looking at potentially investing up to $400 million. So you start with $6.3 billion, and it could be somewhere between $6.3 billion to $6.7 billion, depending on the macro environment.

And the other thing I would highlight is, like I said, with this increased spending in U.S. onshore, a proportion of U.S. onshore CapEx as a percentage of the total CapEx will increase. What that means is a lot more flexibility if the macro is going to become more unfavorable. And so that is one important thing. And I think like Richard said in his prepared remarks, the way we think about capital allocation for U.S. onshore, if you were to adjust our capital program, I mean, first, we look at our efficiency, both operating efficiency and what we’re seeing in the market. Second is potentially how we can defer some of our facility spending. And the last thing would be in terms of activity. So I think from a capital point of view, you’re looking at somewhere between $6.3 billion to $6.7 billion with a larger proportion of U.S. onshore CapEx where we have a lot more flexibility.

Douglas George Blyth Leggate: The Street is obviously very smart, Sunil, because it’s sitting at $6.5 billion right now. So that’s really helpful. My follow-up, if I may, is for Richard. I’ll take advantage and also wish him congratulations for your new role, Richard. I’m thinking a Permian field trip might be in the offing, but we’ll take that one offline. My question is, you did say you’ve added 2.5 billion barrels of resource mostly in the Permian. You’ve obviously got — it looks like sector-leading drilling per lateral foot cost now. And clearly, the breakevens in the Barnett are coming down. So my question is you haven’t given us a resource — drilling backlog or a breakeven for the sustaining capital for the portfolio. So I wonder if you could address those. Where does this leave your drilling inventory? And what would you say is the sustaining capital breakeven at this point for the portfolio?

Richard Jackson: Doug, this is Richard. Great to hear from you and appreciate that for sure. Always enjoy our Permian visits. Let me start just sort of addressing generally why resources. I think for a long time, we’ve been trying to characterize our strong unconventional resource base. And the way to do that was to talk about drilling inventory and think about breakevens against that. I think as we look forward, as we’re explaining today, we’re so much more than that. We have our big opportunities in our conventional assets and just felt like moving to more of a resource explanation was a better representation of what we are and the value that we have. If we sort of break down that 2.5-billion-barrel Permian add, most of that — much of that is coming from continued unconventional shale improvements.

And in our view, this is technology. This is using our subsurface characterization to continue to fine-tune our design, especially around the secondary benches, which we felt like was important to point out in this highlight. It includes things like the Barnett where we had an existing position. Much of that Barnett resource runs into our Central Basin platform where we’ve operated in our enhanced oil recovery business unit for a long time. And so much of that continues, and that would be a direct translation to the drilling inventory that we’ve disclosed previously. But the other piece is the EOR. And we highlight the unconventional EOR today, but also across our conventional position. And so in total, we just felt like that was the right way to think about it.

In terms of the Barnett, obviously, a big piece of that becoming competitive in our portfolio is the drilling cost improvement and just very pleased with the progress by the teams in the Midland Basin for what they’ve been able to do, but we’re seeing that across all of our basins. I think we highlight in one of the slides about a 14% total reduction in well cost across all of our unconventional drilling, same in the Rockies. So in general, that’s improving our resource base. And so I think going forward to the breakeven, we’ll continue to characterize that resource base with a breakeven. I think we’ve talked about our projects for the year, our annual programs are all less than $40 breakeven. And so on a project basis that we expect that to continue.

And like we’ve shown in the past, it’s always improving the resource, expanding it, yes, but improving is the most important component of it and cost is a big part of that.

Operator: And our next question today comes from Arun Jayaram with JPMorgan.

Arun Jayaram: My first question is maybe on Slide 16. Perhaps for Richard, I was wondered if you could maybe give us more details on the demonstration pilot. It looks like in this example, you’re highlighting CO2 injection around 3 years after initial production from the well. But I was wondering if you could just talk about the applicability of this on older wells that may have been completed 6, 7 years ago. And maybe just a little bit about the math around the 2 billion BOE resource opportunity, that would be helpful.

Richard Jackson: Yes. Great. I appreciate that question a lot. The example we’re highlighting on that slide in the Midland Basin, it was with CO2. These wells were originally online in about mid-2015. So your question is perfect. While they apply to historic wells like we’re showing here, they also apply to more recent vintage as well, and I’ll walk through that math in a second. But just a little bit on that pilot. Again, that’s about a 45% uplift. We had 5 injection cycles that were completed over those 3 years, we stopped and saw this 45% uplift. If we modeled out continued cycles of CO2 injection, this is where we get to the 60% and even 100% production uplift. And so that’s where that comes from. If we look at the 2 billion barrels, if you think about recovery factors in the 8% to 12% with unconventional, if you look at this 45% to 100% uplift, now you’re talking about reaching recovery factors in the 15% to 20%.

So that is likely a little bit more for the oil and perhaps a little bit less for the gas in an oil reservoir. But if you look across the derisked unconventional acreage where we have this opportunity, that’s how we began to account for the 2 billion barrels of unconventional EOR. As I mentioned, we’ve got 3 projects that we’ll be working into commercial development over the next couple of years. Those are really spread between New Mexico, Texas, Delaware and the Midland Basin. So again, it’s sort of an approach that can be applied to multiple areas. And then based on this technical work, we have another 30 development-ready projects across these basins that will be ready to develop. And so again, as we think about the role of mid-cycle low decline cash flow in our outlook, we believe these can be very meaningful as we look forward into future years.

Arun Jayaram: Great. That’s helpful. My follow-up is Sunil mentioned that you could redirect $250 million of capital from the reduction in LCV capital back into the Gulf of America for waterfloods in Oman. I was wondering if you could provide some thoughts on the — what you believe these waterflood projects can do to your productive capacity in the Gulf of America. Maybe just thoughts on Gulf output as we think about 2026.

Kenneth Dillon: We now have 2 waterflood projects, FID and GoA. These will result in improved recoveries of nearly 150 million BOE and significant reductions in decline rates over time. Potentially, these could lead to GoA declines going from 20% today to 10% in 2030 and 7% by 2035. So a significant impact on the base. First up is at the King Field, which is a tieback to Marlin. There will be a dump flood, which requires very limited facilities. That will be on stream in Q2 next year. This will lead to a potential extension in field life of around 10 years. At Horn Mountain, we’ve used the latest OBN seismic with our in-house developed tools to place the first injectors. 2 will be drilled in Q1 2027. And in parallel, facilities will be installed in Horn Mountain, leading to a target injection date of Q2 2027 and an expected response date during late summer 2027.

We’ve been ready to go for some time and all the long lead items have now been placed. Returns expected to be in the 40% to 50% range for these projects. So overall, last time I talked about improving well performance, this time talking about lower decline. And as you can see, we’ve had improved reliability, both on rotating equipment and general facilities. We were aided by the weather a bit, including, I would say, being able to get through a lot of fabric maintenance work in this time period. So overall, still working on next year’s plan. Part of that is tying the construction activities for the waterfloods to the planned maintenance required offshore so that we only take the platforms down once and have multiple staggered turnarounds.

Operator: And our next question today comes from Neil Mehta with Goldman Sachs.

Neil Mehta: This is an important time for STRATOS as you guys are ramping this project up. And so as the rubber hits the road, I just wanted to understand what the gating items are and early thoughts around start-up activities.

Kenneth Dillon: Yes. Overall, the STRATOS Phase 1 start-up is proceeding well. Since we last talked, we’ve commissioned the central processing unit with water. Another major milestone was achieved that was starting up the process compression facilities, which are required for CO2 injection. Siemens Energy team, I have to say, including the CEO and the execs have been incredibly supportive of the project. This is a large complex machine, which basically started up first time. We’ve now started loading the first fills of pellets and chemicals and continue to start up the other unit operations. So the next up are the centrifuges and then after that is the calciner, and these are the 2 remaining unit operations before we export the CO2.

We continue to optimize each of the units during start-up as we always do. And while that does cost us some time now, it will pay tremendous dividends going forward. Priorities are to learn for long-term capture efficiency and uptime. So overall, we expect to be circulating KOH this quarter and injecting CO2 in Q1.

Neil Mehta: Okay. And I had a couple of questions around just return of capital as the follow-up. And so I think following the OxyChem sale, I think investors definitely recognize the value in improving the balance sheet, some of the concerns that we heard was about the legacy liability. So I guess this will be the first time you have an opportunity to maybe address that and help people get comfortable around that. And then while I know that you can’t knock out the preferreds until August 2029, is there an opportunity to opportunistically repurchase shares before them to help alleviate some of those concerns. I just want to give you an opportunity to address both of those.

Vicki Hollub: Okay. With respect to the return of capital, we definitely want to take out the — all that we can, the $6.5 billion of debt first. And then beyond that, we are going to opportunistically buy back shares. And we — and it has to make sense. It’s a value calculation for us to determine whether to do that or whether it’s best to take down some more debt or put more into the business. But one thing with respect to the use of cash, I want to make very clear to everybody, and that is that we’re not going to aggressively put lots of extra barrels into an oversupplied market. So when we’re talking about the possibilities here on the call, I want you to understand that we definitely have plans to be very flexible in that.

And I think Richard may have an opportunity later to share more on what that’s going to look like. But we are going to stay within our means in terms of using the cash that we have, but not taking down too much cash off the balance sheet. We’ll try to maintain about $3 billion to $4 billion on the balance sheet as we go forward. And the legacy liabilities with respect to OxyChem, the bulk of those liabilities are outside the operating areas that were purchased. And there’s very little cash being spent or any necessary activities beyond what’s already happening within those assets — operating assets that were bought. Everything else is outside. It made no sense to — for those liabilities to go. And what they’re costing us is right now somewhere in the neighborhood of $20 million or so on an annual basis.

The liability that’s the largest, of course, prosaic, but that prosaic it’s going to be spread over 20 to 30 years. So this is going to take a lot of time to develop that and to work that. And so this really has minimal impact on us to maintain these. It’s really not material to what we do. And the repo — the Berkshire, you want to talk about the Berkshire, Sunil?

Sunil Mathew: Sure. So Neil, like again, I mentioned in my prepared remarks, now that we’ve got a debt target below our goal of less than $15 billion. And as Vicki outlined, we’re going to be opportunistic with respect to share repurchase. It’s going to be driven by the macro conditions, where our stock price is trading, cash on balance sheet because our ultimate goal is to start or resume the redemption of the preferred once we get to August 2029. So what you’re likely to see is as we get towards August of 29, we’re going to start building up cash on our balance sheet. So there is no formula as such in terms of share repurchase, but we’re just going to be opportunistic, considering or keeping in mind that by August 2029, we want to build cash on the balance sheet.

Operator: And our next question today comes from Paul Cheng with Scotiabank.

Paul Cheng: Sunil, can I just clarify that in your 2026 CapEx, you’re saying that you’re going to redirect, say, $250 million from the LCV into the Gulf of America and Oman? So that means that LCV we’re not going to spend any money at all? And also that, I think for Richard, can you talk about the $400 million that on the quick payback onshore project, what kind of production contribution we should expect for 2026? The second question is exploration. With your resource, it seems like you are finding more ways to get resources from the onshore market. So if that means that exploration will remain sort of like not the most important aspect for your program over the next several years?

Sunil Mathew: So Paul, with respect to LCV CapEx for next year, we think it’s going to be around $100 million as we roll off capital with the completion of STRATOS.

Richard Jackson: Yes. I’ll pick up a bit of the scenarios with the potential $400 million that Sunil talked about. I mentioned in my remarks sort of a target initial plan of $55 to $60. And what that means is really, if you think about continuing activity this year, that would be up to that $400 million that Sunil talked about. So actually flat in terms of resources that we would go from this year into next year. In terms of what that makeup for next year might look like for EOR, it’s actually — it’s light. It’s about $100 million between EOR and unconventional EOR. And so it’s fairly light next year. And it’s actually pretty capital efficient as we look in the out years because we’re not drilling wells, we’re using CO2 in terms of the recovery.

But I also want to highlight, we work scenarios below the $55 plan. And that’s one of the advantages of the allocation of capital into the U.S. onshore. We have plans that go below $50 to be able to adjust to really carry Oxy in total in terms of cash flow to meet a breakeven and obviously cover our uses of cash. So we have that mapped out. We’ve done it in the past. That’s why we wanted to go into some detail on the thought process of how we react to lower oil prices. Obviously, we like to work through efficiency first, but we do have that activity flexibility in our operations, especially in the U.S. to adjust in lower oil price scenarios.

Kenneth Dillon: And then following up in GoA, we are — we’ve already started deferring some exploration from next year into the following years. And in Oman, these are not really big exploration. These are step-out wells very close to our existing facilities, which can be brought online incredibly quickly.

Operator: And our next question today comes from James West at Melius Research.

James West: So Vicki, maybe a bigger picture question for you. A lot of moving parts the last several years with Oxy, lots of changes in the portfolio. You’ve been busy is the key here. With the OxyChem sale, are we going into now a quieter period, maybe a harvesting type of a period?

Vicki Hollub: Absolutely. And I’m thankful to be at this point finally. Yes, we’ve gone through — there was a lot, as you said, going on, but this is where we wanted to be, and this is where we needed to be. So we’ve done everything that we set out to do with respect to being mostly a U.S. company with very high-quality, high-margin assets and assets that can sustain over the long term. And we think that our portfolio is so much differentiated from anybody else because we not only have the high return but high decline shale, it’s complemented and will be complemented in the future by the conventional assets and conventional EOR, along with unconventional EOR. And when we look at where our portfolio stands today of the — our production, where we — our total development, 45% is conventional and 55% is unconventional.

Going into the future, we have a ratio of — looks like about of the total $16.5 billion that we have in resource, about 65% is unconventional, 35% conventional. But the beauty of the unconventional is what Richard talked about, and that is the fact that in the unconventional, we are going to be able to do — use CO2 for enhanced oil recovery in the unconventional. It’s going to recover, we believe, up to the same amount as primary production. So we’ll get 100% of what we got before. So we’re doubling our total recovery from the unconventional. So that will be actually low decline as well over time. So we think that versus a pure shale player or versus those that have assets that are difficult to manage internationally and in foreign countries, we think that we’re much better positioned with this portfolio.

So yes, we’re done with anything that’s — any big acquisitions or anything like that.

Operator: And our next question today comes from Matt Portillo at TPH.

Matthew Portillo: Maybe just a question to start out on the DJ. You highlighted in Q3 strong well performance drove upside to your production figures. I was curious if you could just maybe comment on in the Rockies, if you’ve changed anything on the completion or spacing design? Or what’s really driving the outperformance there?

Richard Jackson: Yes. Thanks. A big part of that beat really the last couple of quarters has been our base production. And so a lot of work we’ve talked about in the past, we’ve been doing around artificial lift, even using some analytics to improve our efficiency on that. So that was the biggest part of it. We have had better new well performance as well. I wouldn’t call it major changes. We just continue to tweak sort of our subsurface designs and our flowback. The base actually — the production operations that support the base also help our new well production. And so a lot of that new well beat is just better uptime on some of our processing facilities.

Matthew Portillo: Great. And then maybe just a follow-up on the inventory. I was wondering if you might be able to comment on your views around your DJ inventory and how you might be able to flex capital in kind of a lower commodity price environment, just thinking through kind of the remaining locations left and obviously, some of the upside that you’ve highlighted here in the Permian, how you can flex capital between those 2 basins?

Richard Jackson: Yes, that’s great. Yes, we’ve been largely working in the DJ around an optimized activity set. We’ve had a couple of rigs and one frac core. And so that’s been a big piece of it, continuing to show efficiencies, like I said, on well costs earlier. I think in the Rockies, as we look to the future, excited about the Powder River Basin. We continue to make progress there. We sort of have been working similar to the way I’ve described the Midland Basin, where we — first, we’re sort of proving out the productivity of the wells really in the ’23, ’24-time frame. And then in ’25, we’ve had a partial rig year where we flexed the rig up to the Powder River Basin. We’ve had really drilling record after drilling record up there.

We’ve improved about more than 25% versus the last year in terms of drilling performance. So that was a bigger part of it. And so now really, as we look to ’26 and beyond, we have that opportunity to flex from the Rockies to the Powder River Basin. And so again, I don’t really see an increase in capital, just more optimization in terms of that portfolio for the Rockies with that.

Operator: And our next question today comes from Neal Dingmann at William Blair.

Neal Dingmann: My question is just on the low Permian well cost that you all showed for maybe for Richard. Is the larger projects contribute to that? Or what was the main driver of that exceptionally low cost?

Richard Jackson: Yes. Great question. We’ve been on this mission in the last couple of years to really relook at both the operational efficiency of our operations and working, like I mentioned earlier around our contracts and service contracts. And so it’s really been a bit of both. I’d say the scale in the Midland Basin certainly helped. We were able to combine really the best of the best from Oxy and our CrownRock — legacy CrownRock team and really just worked on that piece of it. But the scale certainly helped. So I do agree with that. But from an efficiency or from a contract standpoint, I think we were also entering a period where we made sure we were getting the right contracts for the right type of work. And so we’ve done a lot of work on that. We’re fairly short right now in terms of contract term. And so we’re working hard with our partners there to kind of think about how it looks going into 2026 and making sure we got those 2 pieces put together correctly.

Neal Dingmann: Great point. And then just a follow-up, Richard, you talked a lot on the conventional EOR today and the amount of possible recoveries there. I’m curious, what type of returns? I assume the returns around some of that incremental upside would be very positive, I would think, correct?

Richard Jackson: Yes. We highlighted 25% to 35% kind of where we’re at today. And so if we’re able to increase the uplift like we’re talking about, those are only going to get better. So the goal, obviously, is to be competitive in our portfolio. And so the teams will be working on that. And that — again, that’s the beauty of the portfolio that we have. It’s not so much the expansion, but it’s the competition to make sure that we’re putting capital where best placed for the returns that we want.

Operator: And our final question today is coming from Leo Mariani with ROTH.

Leo Mariani: I really appreciate all the details on ’26. You certainly talked about the range of capital, $6.3 billion to $6.7 billion. Very helpful. Can you give us just some high-level indications of what would you kind of expect production to do in that range? Is that kind of a maintenance range for production maybe at the lower end and maybe you see a modest amount of growth at the high end? What can you kind of tell us about kind of associated production?

Sunil Mathew: So in terms of production, you would be looking something close to flat to potentially up to 2% growth.

Leo Mariani: Okay. That’s very helpful. And I guess any specific areas that largely kind of unconventional that kind of provides the growth for next year? Is that kind of the flex piece is really that $400 million, which I guess is mostly unconventional Permian?

Sunil Mathew: That’s right. So the growth will be largely driven by unconventional Permian.

Richard Jackson: Right. And as I mentioned, the flex down will go after efficiency first to maintain activity, but in position to be able to cut activity as required based on the macro.

Operator: Thank you. And that concludes our question-and-answer session. I’d like to turn the conference back over to Vicki Hollub for any closing remarks.

Vicki Hollub: Before we close, I want to express sincere appreciation to the entire OxyChem team for their steadfast commitment to safety and operational excellence. Their achievements have contributed significant value over the years, and we’re confident that OxyChem will continue to thrive under new ownership. So thank you all for your questions and for joining our call today.

Operator: Thank you. Today’s conference has now concluded, and we thank you all for attending today’s presentation. You may now disconnect your lines and have a wonderful day.