Occidental Petroleum Corp (OXY) — Q2 2025 Earnings Call Transcript

Thank you, Drew. Good afternoon, everyone, and thank you for participating in Occidental's Second 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, President Operations, U.S. Onshore Resources and Carbon Management; 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.

Thank you, Jordan, and good afternoon, everyone. I'd like to first thank our teams for another quarter of strong performance, delivering $2.6 billion of operating cash flow in the second quarter. This helps to generate more operating cash flow in the first half of 2025 than we did in the first half of 2024, despite much lower oil prices in the first half of 2025. In fact, WTI averaged $11 per barrel lower in the first half of 2025. And for reference, those cash flows are talking about cash flows before working capital. Next, I'd like to congratulate our teams for their ability to optimize our portfolio in a way that strengthens our future development plans while creating divestment opportunities that, along with cash flow, made it possible for us to repay $7.5 billion of debt and less than a year from closing the CrownRock acquisition, that's well ahead of target. This equates to almost a 70% reduction of the debt raised for the acquisition. Also, I'm pleased to report that STRATOS has achieved a significant milestone, and we're on track to start capturing CO2 this year. This timing is perfect as there is growing momentum behind Direct Air Capture to generate meaningful value from CO2 Enhanced Oil Recovery, or EOR, and Carbon Dioxide Removal credits, or CDRs. Before I turn the call over to Sunil, I’ll now provide a little more detail on operations, debt reduction, and STRATOS. In the second quarter, our oil and gas business produced 1.4 million BOE per day, exceeding the midpoint of our production guidance. This reflects both the operational strength of our teams and the caliber of our diverse portfolio, with outperformance in the Rockies and an uplift to our Oman volumes due to the Mukhaizna contract extension, more than offsetting production impacts primarily due to third-party constraints in the Gulf of America. Back to cash flow generation. Despite much lower oil prices, the teams achieved higher CFO, or cash flow from operations, this year versus the same period last year, due in part to the additional production from CrownRock as well as some production growth from legacy Oxy. But important to note is that our oil and gas teams were able to achieve enough operating cost reductions to offset the operating costs associated with the incremental 180,000 BOE per day of production. In other words, despite oil production rates of 1.395 million BOE per day in the first half of this year versus 1.215 million BOE per day in the first half of 2024, absolute operating cost in those two periods were essentially the same. I’ll highlight some of those activities that have contributed to reductions in our total cost structure. In our onshore U.S. operations, we announced in our first quarter earnings call, $150 million in expected operating cost savings this year through significant cost reductions. As I just highlighted, holding absolute cost level with increased production resulted in a meaningful reduction of per barrel cost to $8.55. By integrating automation, field sensors, and artificial intelligence to prioritize lease operating routes, we have transitioned approximately 40% of our onshore production to ruthless operations. And in our EOR business, increased field interconnectivity has enabled us to optimize our use of recycled CO2, and advanced subsurface modeling has helped to improve the effectiveness of each molecule we inject, thus enabling us to reduce our purchased CO2 volumes. In our international operations, we have implemented similar efficiencies to reduce OpEx for the year by an estimated $50 million. We are confident in the sustainability of these cost reductions as the majority are structural in nature. Across the Permian, our teams have consistently driven down well costs through enhanced efficiencies, enabling us to reduce the midpoint of our capital guidance by an additional $100 million this quarter. In the Delaware Basin, drilling times have improved by 20%, bringing well cost below our 2025 target. Meanwhile, in the Midland Basin, our best-of-the-best workshops have facilitated the rapid sharing of valuable well design and operational insights across the organization, yielding impressive results. In the first half of this year, well costs for both our legacy Midland Basin assets and our CrownRock assets were lower than the expectations we set earlier this year. Collectively, these advancements have resulted in a 13% reduction in year-to-date Permian unconventional well costs compared to 2024. The capital efficiencies, along with continued improvements in recoveries, have yielded robust economics from secondary benches and have helped to sustain year-on-year improvements in our capital intensity. We also delivered strong well performance offshore. I'd like to highlight two recent standout wells in the Gulf of America with one of the best at Horn Mountain in 22 years and the best at Caesar Tonga in 13 years. Both are on production down and ramping up through the end of the year. This is due to the success of our subsurface engineering and the resource potential across our existing fields, which will be enhanced by future water flooding that will unlock significant value going forward. Our Midstream and Marketing Segment had another impressive quarter, generating positive earnings on an adjusted basis and outperforming the high end of guidance. This was largely due to improved crude marketing margins, gas marketing optimization, and higher sulfur pricing. We also benefited from new oil transportation contracts that began during the second quarter. Turning now to our Low Carbon Ventures business. In just two years since groundbreaking, STRATOS has achieved a significant milestone with Trains 1 and 2 now moving over to operations. We've commenced wet commissioning with water circulation and are on track to start capturing CO2 this year. We are immensely proud of the achievements to date and the exceptional record of safety performance as we advance toward commercial startup. As I've shared in the past, we see immense value from taking a phased approach to STRATOS development. Even though this is a first-of-its-kind facility at this scale, we're already benefiting from continuous evaluation and learnings along the way. For example, we've been able to capture lessons from commissioning as we move into operations and are incorporating the latest R&D out of our Carbon Engineering Innovation Centre into Phase 2. Not only will this improve the project's economics when the full capacity is online, but it will accelerate the cost down curve for future DAC projects. Since the first quarter, we signed two additional commercial agreements for carbon dioxide removal cells with JPMorgan and Palo Alto Networks. The majority of volumes through 2030 from STRATOS are now contracted, demonstrating the strength of the growing CDR market and increasing appetite for durable carbon removal technologies. We also announced an agreement to evaluate a potential joint venture to develop a DAC facility in South Texas with XRG, which is the UAE's investment company in gas, chemicals, and low carbon energy solutions. Agreements like this, along with the U.S. Department of Energy support, highlight Oxy's unique capabilities and signal confidence in DAC as an investable technology to provide both high integrity carbon removal and support energy development through Enhanced Oil Recovery in the United States. The recently enacted One Big Beautiful Bill included a number of provisions that will help Oxy continue to deliver differential value to our shareholders. One of these is the extension and expansion of the 45Q credit driven by the recognition of the need to capture CO2 for use in EOR to support U.S. energy security. The new law levels the playing field between carbon storage and utilization pathways like DAC to EOR. Both can and likely will play an important role across global energy supply chains and carbon management. We believe that carbon capture in DAC, in particular, will be instrumental in shaping the future energy landscape. First, captured CO2 can be used for Enhanced Oil Recovery in conventional and shale reservoirs. We believe this proven technology could recover an additional 50 billion to 70 billion barrels of oil in the United States, which could extend our energy independence by 10 years. Second, CO2 removed from the atmosphere via DAC can be used today to address submissions related to products or services, specifically CDRs from DAC can be paired with any fuel or energy source to provide a low-cost, scalable solution for growing low carbon intensity fuel, conventional or energy markets. Oxy is uniquely positioned to deliver both through our leadership in DAC technology, sequestration, and EOR operations. We have over 50 years of experience in carbon management and nearly 3 billion barrels of Permian EOR conventional resources along with extensive CO2 infrastructure in the Permian. In addition, we have our expanded U.S. unconventional runway and our well-positioned sequestration hubs. As the largest acreage holder in the Permian, we have the scale along with the ability to add secondary benches and EOR to provide lower emission barrels and further support U.S. energy security. Before turning to Sunil, I'd like to highlight the recent success of our portfolio high-grading efforts. Since the end of the first quarter, we announced $950 million of additional divestitures, selling non-core largely non-operated assets in our U.S. onshore business. This brings our total of announced divestitures to nearly $4 billion since January of 2024, enabling us to accelerate our debt repayments and improve our balance sheet. Through our high-grading efforts, we have strengthened our portfolio, divesting assets with limited near-term opportunities and growing our inventory of competitive high-margin opportunities. We have seen tremendous success so far across our CrownRock acreage, realizing significant improvements in well cost and efficiencies, and it keeps getting better. We expect value creation to expand as we continue to harness cross operational synergies throughout our Permian operations. I'll now hand the call over to Sunil to review our financial performance and discuss our second half guidance in more detail.

Thank you, Vicki. In the second quarter, we generated an adjusted profit of $0.39 per diluted share and a reported profit of $0.26 per investment income, partially offset by positive mark-to-market adjustments. Strong operational performance and the continued focus on capital efficiencies enabled us to generate approximately $700 million in free cash flow before working capital despite lower realized oil prices and high market volatility. We had a positive working capital change primarily driven by reductions in commodity prices, fewer battle shipments on the water and lower interest payments, which is typical for the second and fourth quarters. These impacts were partially offset by a $110 million tax payment related to 2024. After warrant proceeds and debt repayments, we exited the quarter with approximately $2.3 billion of unrestricted cash on the balance sheet. Our effective tax rate increased in the second quarter due to a shift in the jurisdictional mix of income driven by lower anticipated full-year oil prices compared to original expectations. We are guiding to an adjusted effective tax rate of approximately 32% for the third quarter with our full-year effective tax rate in a similar range based on current commodity prices. Our strong operational and financial performance can largely be attributed to higher volumes across our U.S. onshore and international portfolio, offsetting lower-than-expected production out of the Gulf of America. New well and base production outperformance in the Rockies and the net production uplift in Oman from the Mukhaizna contract extension enabled us to outperform the midpoint of guidance. Our domestic lease operating expense in the second quarter notably outperformed guidance at $8.55 per barrel. This outperformance was due in large part to early success in delivering U.S. onshore operating cost improvements plus timing impacts of offshore production engineering work shifting from the second to third quarter. As Vicki shared, this reflects our commitment to achieving operational efficiencies and continuous improvement with notable savings realized in the Permian. Looking ahead, the outlook for the second half of the year remains strong. In the third quarter, we expect our total company production range to increase to 1.42 million to 1.46 million BOE per day as we sustain operational momentum and anticipate higher volumes in all of our main operating areas. Though we expect a quarter-on-quarter increase in produced volumes in the Gulf of America, the recent curtailments and the shift in program timing will have lingering effects prompting a reduction in our offshore second-half production guidance. We are maintaining total company production guidance for the year as a stronger outlook on new well and base performance across our U.S. onshore assets and increased production in Oman from our Mukhaizna contract extension are expected to offset lower volumes in the Gulf of America. This modified production mix is expected to slightly reduce annual total company oil cuts. As Vicki said, our Midstream & Marketing segment performed exceptionally well in the second quarter, generating positive earnings on an adjusted basis of approximately $206 million above the midpoint of guidance. This was largely driven by enhanced crude marketing margins due to timing impacts of cargo sales and fluctuations in commodity prices. We also benefited from gas marketing optimization and higher sulfur prices at Al Hosn during the quarter. Given the strong second-quarter performance, we have raised full-year Midstream & Marketing guidance by $85 million. We anticipate a more muted third quarter, assuming the Waha to Gulf Coast natural gas spread continues to narrow, and we'll be prepared for any marketing optimization opportunities as they arrive. Our second-quarter OxyChem pre-tax income came in below guidance due to weaker-than-anticipated pricing for caustic and PVC. Demand held firm, but excess supply in both the global and domestic markets compressed margins. While the domestic PVC demand is typically the strongest in the third quarter, it is not expected to be strong enough to offset the oversupply in the market. Based on these market conditions, we are lowering OxyChem's full-year guidance range to $800 million to $900 million. Turning now to our capital program. We expect the remaining 2025 capital spend to be more weighted to the third quarter due to the timing of oil and gas activities and the construction schedule for the battleground expansion. Continued momentum in operational efficiencies across our Permian assets has enabled us to further reduce our 2025 capital guidance range by $100 million without impacting total company production. Together with the $50 million in operating cost reductions from our international assets and the cost reductions of $350 million announced in May, we now expect $500 million in total reductions relative to the original plan. In the first quarter earnings call, we highlighted several key non-oil and gas items contributing to incremental pretax free cash flow in 2026. Another impactful driver is the recent passing of the One Big Beautiful Bill. In addition to the benefits Vicki highlighted from the preservation of 45Q credits, the bill will provide significant cash tax benefits to Oxy for the remainder of 2025 and 2026 relative to prior law. Based on our preliminary assessment, we estimate a potential $700 million to $800 million reduction in cash taxes, with roughly 35% expected to be realized in 2025 and the remainder in 2026. These benefits are primarily due to changes to bonus depreciation, R&D expensing, and limitations on interest deductibility. Before I close, I would like to provide an update on our strengthening financial position. As Vicki shared, our portfolio high-grading efforts are progressing with the announcement of $950 million of additional divestitures since the end of the first quarter. Of this, $370 million has closed, and we expect the remaining $580 million to close in the third quarter. This brings the total of announced divestitures to nearly $4 billion since the first quarter of 2024. The success of our divestiture program to date, coupled with warrant proceeds and strong free cash flow, have enabled us to be ahead of the schedule on the debt reduction targets outlined when we announced the CrownRock acquisition. In the last 13 months, we repaid approximately $7.5 billion of debt, far exceeding our near-term goal of paying down $4.5 billion of debt within 12 months of closing the CrownRock acquisition. This reduces annual interest expense by approximately $410 million and also results in a much more manageable debt maturity profile. We are extremely pleased with the progress of our divestiture program and the trajectory of our debt reduction plans. Together with recent step changes in operational efficiency and key non-oil and gas catalysts, our continued focus on strengthening the balance sheet will support a stronger foundation for delivering long-term shareholder value. I will now turn the call back over to Vicki.

Thank you, Sunil. To close, I'd like to reiterate the strength of our upstream portfolio. I believe we have built Oxy's best-ever portfolio of high-quality complementary assets. These are a diversified mix of short-cycle, high-return unconventional assets along with lower decline, solid return conventional reservoirs. And we have the best talent and capabilities in our history and with our team's continued focus on performance and innovation, enabling us to deliver outstanding results and to position us for the future. We have an incredible runway in front of us with over 14 billion barrels in total resources, much of which is well-suited for EOR application. Our industry-leading experience in carbon management and EOR operations is a key differentiator for Oxy and will enable us to unlock additional resources and deliver long-term value for our shareholders. With that, we'll now open the call for questions. As Jordan mentioned, Richard Jackson and Ken Dillon are here with us today for the Q&A session.

The first question comes from Arun Jayaram with JPMorgan.

Sunil, I wanted to just follow up on the cash tax rate or your expectations of tailwinds from the One Big Beautiful Bill. You mentioned $700 million to $800 million of tailwinds. I think you said 35% in '25 and the balance in '26. Is that correct? And maybe help us think about what that would translate into a cash tax rate perhaps in '26?

Arun, firstly, that is correct. 35% of the $700 million to $800 million benefit will be in '25 and the balance is going to be in 2026. So the way we are to look at it is the adjusted income effective tax rate will not be impacted by the cash tax benefit, but what you're going to see is an increased deferred tax expense, primarily driven by the acceleration of depreciation and R&D expenses for cash tax purposes. So you can go based on the guidance in terms of the book tax rate, but what you're going to see the difference is on the deferred tax expense increasing due to this benefit.

The next question comes from Doug Leggate with Wolfe Research.

Vicki, it's a long time since we heard much about Mukhaizna. I seem to remember when Ray had that contract signed, gosh, about 20 years ago now. The press has you spending committing $30 billion through 2050. And I recall that there are significant cost recovery benefits from stepping back up the spending. So I just wonder if you can walk us through what the free cash implications are? We obviously saw the initial step up in production in Q2.

Yes. I'd say, Doug, that was an incredible agreement that we made with Oman because the benefits both Oxy and Oman allows us the flexibility and possibility to invest over there because now the economics will be comparable. And Ken, did you have anything to add?

Doug, it's Ken. I can't really comment on specific numbers around the contract. But if you think of that number being both capital and expense perhaps, and then you look at our equity in the book, which is less than 50%. And you start looking at that capital between now and 2050, you get into the sort of numbers you would expect for us. The other thing I would say as you look back to the days that you mentioned since then, we've produced 640 million barrels to date. And originally, it was very focused on the steam floods. With all the work we've done there, what we see is multiple stacked pays across a very large block. And in the north, we've been producing the layup wells for some time now, which are totally different and don't need any steam. So we see the extension as a win-win for Oxy and the government and sustainable. And as Sunil said on the last call, you'll see the numbers roll through the books over time.

And you'll note, Doug, that we much prefer those areas that have stacked pay and give you multiple options and lower cost on infrastructure ultimately.

Will be limited to one? Or can I have a follow-up?

You can have a follow-up.

Okay. So my follow-up, Vicki, is the $1 billion of non-core asset sales kind of came out of nowhere, especially the sale to Enterprise. So I wonder if you could take a kind of 5-year forward look or however long you would like to put on it and say, well, we actually have another X billion dollars of non-core asset sales that kind of augment the free cash flow in terms of deleveraging. What would the scale of that non-core asset bucket look like for potential sales over that period of time?

We have a significant amount of scattered acreage that stretches from here through the Rockies and into the Virginias, accumulated through various acquisitions over time. While much of this acreage doesn’t hold substantial value at the moment, it requires some cleanup and consolidation before we can sell it. Eventually, we plan to sell these assets, but they won’t generate large returns. Currently, the team is focused on organizing and preparing these assets for sale.

And I apologize, I have Arun Jayaram, for his follow-up. His line is disconnected. We'll go to the next person, Betty Jiang with Barclays.

Vicki, considering your comment about OBB's advantage regarding 45Q and the carbon business, does this shift your strategic focus on the carbon business towards exploring more point source opportunities for EOR purposes, especially in light of the utilization parity you mentioned?

Yes. We have always been interested in point source capture. In fact, that interest sparked our desire to advance the technology of Direct Air Capture. From around 2008 until we discovered Direct Air Capture, we were focused on point-source capture. At that time, the market for carbon credits for this type of capture was so low that we struggled to persuade any industry to participate. Now that there is parity for CO2 enhanced oil recovery, we have not abandoned that effort. We will continue exploring point source opportunities, especially since there are significant emissions within pipelines that could transport CO2 to the Permian. I hope this will encourage industrial sources of CO2 to collaborate with us.

Betty, just one quick one, this is Richard, to add. I would say one sort of tailwind that's helping us natural gas to power generation, especially in places like the Permian. And so for us, we see that link not only for the power supply but from a CO2 source as well as we're able to incorporate carbon capture into some of those installations.

It's very impactful for the EOR business for sure. My follow-up actually back to cash taxes. What would be the cash tax saving potential beyond 2027? Do you go back to where it was before? Or do you continue to expect savings?

Beyond '26, it will depend on the capital trajectory and on the proportion of domestic spending. So today, if you look at our capital, around 90% of it is domestic and we don't expect any significant change in that mix. And the reason we highlighted the '26 estimate is because we have the battleground expansion project that is expected to come online next year. And so we're expecting more 100% bonus depreciation qualifying assets in '26 compared to '25.

Once again, we'll try again Arun with JPMorgan. Please go ahead with your follow-up questions, sir.

Apologies about that. I forgot how to use a phone. A quick question on the Gulf of America. I wanted to get your thoughts on how you think about the production capacity in the Gulf of Mexico trending over a multiyear basis as you implement some of your Gulf of America 2.0 projects. And I think this year also was impacted by a higher degree of turnarounds and maintenance.

Yes. I think looking forward, the first layer that builds in is the water floods, which we've talked about briefly before. Having those projects online will reduce the average decline rate for our fields and lead to flat, low-cost, steady barrels. We have a large number of projects lined up for most of our facilities. If you look in the East, some of the modifications we've made recently offshore increase the capacity from our Eastern facilities. I think in the central GOM area, as Vicki mentioned, we're seeing wells that are coming in with very large EOR. One of them could potentially end up as one of the best Gulf wells we have ever drilled. So I think the combination of the subsurface engineering that's being carried out along with the geo signs, I think layered on to what we've done over the last three years in terms of getting equipment reliability and availability means that we're positioned incredibly well going forward for the production ramp-up.

The next question comes from Nitin Kumar with Mizuho.

I want to start off on the pretty impressive cost savings you highlighted both in the Delaware and the Midland. CapEx for the year was only down about $100 million. So I know you won't give me a budget for next year, but as I think about rolling those savings, could you talk about how Lower 48 spending might trend in 2026, given the efficiencies you're seeing?

Yes. I would say that you're right that next year, we will have a reduction in our OxyChem spend by about $300 million and a reduction in LCV by $250 million. That, along with the efficiencies that the onshore team is building and achieving that could create some opportunities for higher capital. You want to comment some on that, Richard?

Sure. I appreciate the opportunity. The team has done an outstanding job managing both capital and operating expenses. Regarding capital, we have an additional $100 million reduction this quarter, which adds to the $100 million reduction from the first quarter, totaling $200 million below our original plan. We do see potential moving forward to maintain and even improve this situation. We are experiencing success in drilling efficiency, including reducing nonproductive time and increasing pad sizes from 2 to 3 wells earlier this year to 4 to 6. Our completion teams are also achieving better efficiency results. As we move toward 2026, we are focusing on optimizing our activity levels for greater efficiency. While we're not specifically aiming for growth, we are concentrating on what is needed to sustain these efficiencies. Currently, we are at a nearly optimized activity level, and we will monitor it closely over the next several months to see if efficiencies could allow for adjustments in activity. We will ensure that our schedule aligns correctly as we approach 2026.

And I'd say the other place that we could shift some capital would be to the lower decline, low F&D, high-margin, waterflood projects that are being targeted for the Gulf of America.

That's a perfect segue to my next question. So I appreciate you team me up, but I was going to follow up on Arun's question. As you put behind the Horn Mountain pipeline issues that have dogged Gulf of America this year, what would be a good, steady sort of run rate for the Gulf of America, let's say, in '26 and '27 from a production standpoint? And could you help us bridge the gap from where we are today between new developments, these water floods, et cetera, and also a return or sort of curtailed constrained production right now?

Thanks for the question. I think if we maybe do it in reverse order, operationally, we experienced a mix of things, including pipeline constraints. But as Vicki highlighted, we've also seen incredibly positive results in our wells this year. We modified our pumps in Eastern GOM to handle the constraints. This work was done successfully in Q2 with really great work by our teams, both onshore and offshore. Going forward this year, we were hurt by the late arrival of a stimulation vessel, which has been doing work for another operator. But these elements have all been built into our ramp-up plan, and we expect a very strong exit rate, as you can see from the numbers. In terms of next year's guidance, with the Gulf, it's all about optimization and planning. Over the last few years, as you know, we've really improved the availability and plant uptime. The next phase of our OpEx optimization is to move to turnarounds every 2 years. And that multiyear schedule is being poured at the moment, including mapping resources internally, externally, and tied to vendors that can service us through the long term. So we're considering starting that next year. So more information to come on the '26 plan later this year.

The next question comes from Neil Mehta with Goldman Sachs.

Yes. Looking at Slide 34, you talk about advanced subsurface characterization and technological improvements. And I think a lot of investors are just wondering what inning are we in terms of digital application in the oil fields and how are you employing it? And do you think it's going to fundamentally change the industry and our ability to drive volumes?

We are so excited about what we've been able to do internally with Oxy to start building our AI capabilities. And I think we've talked on this on the calls previously about our AI effort in the Gulf of America. That subsurface is so incredibly complex that we do believe that we can make a big difference with the project that we're working right now. And we expect that maybe by the end of this year, we'll be prepared to start having the team look at actually executing some things in the year to 2 years following. So Gulf of Mexico or Gulf of America, that's going to be an area that where AI is really going to be applicable. It's already helping us with the subsurface in the Permian and in the other onshore areas in the U.S. It's also helping with not just the subsurface, it's helping with operational efficiencies. So we have really put a big effort into making sure that we have actually focused teams. These are teams that are focused on specific areas. One, is right now working operations. The other is working in the Gulf of America. Then we have a group that's working with the broader challenges of logistics and supply chain and things like that. So we put a big effort forth on it, and I do believe it's going to deliver significant results.

Vicki, maybe tie that into your perspective on U.S. oil production and how you see that evolving as we apply these technologies. We've got to contrast that with maturity in a number of these key basins and limited exploration success on the oil side at least. And so just how do you see the U.S. production profile evolving over the next 5 years?

Well, we've been talking about this a lot. We believe that the U.S. could hit peak production between 2027 and 2030. And we've modeled that based on hovered curves and the current data that we have. We've taken the model down to look at conventional separate from unconventional and also to look at EOR. So we believe that right now, there's going to be significant potential and maybe the extension of our U.S. energy independence by about 10 years with the development of 50 million to 70 million barrels of oil developed by and through CO2 EOR. So it's, to us, incredibly important because energy independence for the United States really impacts our ability to maintain our leverage in the world. So we believe this is critically important for us, it's always been a strategy to use CO2 for enhanced oil recovery. We're a company that's always been known for getting the most barrels out of any reservoir that we work. And CO2 is, in our experience, over the 50 years that we've been doing it, it's been able to extract more than any other technique that we've tried beyond primary production and water flooding. So we do believe that out of the estimated 1.5 trillion barrels of oil that the United States has in terms of total resource in the ground. Currently, only 22% will be recovered unless we can apply CO2 EOR. And CO2 EOR will get us double-digit increases from that amount, we believe. And again, the 50 billion to 70 billion barrels. We're working on that. That's our strategy. We're working the technology to get the CO2 because the other challenge is that there's not enough naturally occurring CO2 in the United States to support the development of that kind of volume.

The next question comes from Paul Cheng with Scotiabank.

Vicki, on Oman, the term sounds fantastic, and you guys know what to do, and there's a lot of opportunity. Is the activity level, right now, being constrained by your capital? Or is there any other thing that is constraining the activity level so that you can't do or go a bit faster?

Well, what's happened with this contract is certainly going to make that project a lot more competitive. So there's no restrictions with respect to what we can consider there, but the main restriction for us in terms of capital and for the industry itself is right now, we have an oversupplied market. And so there's, in our view, no reason for companies to get too aggressive with the growth right now. You're just making the problem worse if we do that. And for us, we are absolutely determined to get our debt down sooner rather than later. So we are now running at a level where our activity level is designed to ensure that we can maintain our production and that we generate the projects at the pace that we need to. So we're not looking for growth. As Richard had said, we're looking for the activities that can help us continue to optimize, reduce our costs and lower our cost structure. And I can tell you that every one of our asset teams, including midstream and chemicals, works every day to find ways to lower our cost because we believe that at the end of the day, it's going to be the lower-cost company that really is profitable through all the cycles and the one that has the sustainability over time. With the portfolio we have, we have the chance to do that. And we're doing it now. We'll continue doing it. But the next step is to get our DAC costs down to the point where the CO2 cost enables us to generate maximum returns from those CO2 floods. And with respect to Oman in particular, it's ultimately going to be a place where there will be incremental capital. We'll just have to figure out when that's going to be. What do you think, Ken?

Yes. To add to what Vicki mentioned, we are seeing improvements in both capital and operational efficiency in U.S. onshore. In Block 53, our drilling rigs are operating at their lowest costs per foot and achieving their highest rates of feet per day. Regarding operational expenditure efficiency, our artificial lift equipment is demonstrating its highest reliability, and our workover rigs are performing at optimal levels. All of this has been accomplished while maintaining excellent safety performance, aided by our teams in the center utilizing AI. We are achieving more by working smarter, which involves a mix of engineering initiatives and supply chain enhancements. We are addressing supply chain concerns globally, and we are observing positive impacts onshore, offshore, and across our assets worldwide, with more opportunities on the horizon. So, we are accomplishing a lot with fewer resources.

Can I just continue on this subject? Because let's assume, say, several years down the road, you guys have already restored your balance sheet and there's a call on oil. And so oil is needed. At that point, I'm trying to understand how big the scale of the Oman business can get to? And what is the constraining factor at that moment?

The constraint for us would be our value proposition because it's not just about growth for us. Our value proposition is that we want to deliver a growing dividend, but at a moderate pace. We want to, in the near term, lower our debt. But over time, we want to add share repurchases to our program in addition to investing appropriately in our organic assets. So we will, over time, need to increase our production, but it would be at the appropriate time. And when that happens, we'll allocate capital based on not just what the returns are but how it fits within our long-term plan because as we've said, our portfolio is diverse. We have the high-return shale, but high decline. We have the low-return assets like Oman and where Oman comes in is providing us those lower decline and lower capital cost projects.

Just maybe I could add something to that. If you look at the portfolio in Oman, what we have is a number of blocks where we already have partners. If you look at the South, it's predominantly heavy oil, but with some lighter oil. In the Northwest, it's light oil. And then in the East, it's gas, and we mentioned our discovery recently. Some of these blocks, we do not have partners. So we have opportunities to use partnerships as a way of funding projects also to accelerate things, but without digging into our own capital going forward. So we have a huge range of options with very low option cost at the moment as we work through things.

The next question comes from Kevin MacCurdy with Pickering Energy Partners.

I wanted to ask on the trajectory of OxyChem income. Do you view the PVC oversupply and price decrease as temporary? And how is that factored into your outlook for a big free cash flow uplift in chemicals next year? And just one for me.

So in terms of the '26 market, it's going to, to a large extent, depending on the timing of the supply-demand balance. And so currently, the global supply-demand for PVC and caustic is being burdened by additional Chinese capacity, which, again, is burdening the export prices and ultimately burdening the domestic prices. So if you look at the Chinese exports on the PVC side, it's grown from almost nothing in 2020 to almost 30% currently. And the same with caustic, it's been increasing and it's still growing. So some of the announced capacity rationalization in Europe and U.S. will potentially mitigate some of those capacity additions, but we don't see a meaningful impact of that in 2026. Also, we believe that the integrated margins between PVC and caustic are close to the variable cost of many international producers, including China. So we don't anticipate further sustained declines in margins, but as far as '26 goes, we believe it is more likely to be what we saw in 2025.

The next question comes from Matt Portillo with TPH.

Just a question on the Permian. I'm curious, as you guys think about the production in the basin. We've seen a little bit of a downtick in the oil cut and a rise in your gas and NGL recoveries. I was curious if that is a function of the secondary zones being developed or if you're having just better recoveries overall in the gas and NGL side? And then as you look into the back half of this year, especially given the high input costs in Q2, do you expect that oil cut to stabilize or even improve a bit into the second half of 2025?

Yes, I appreciate the question. Let me go through a few points on this. Overall, in the U.S. onshore, particularly in the Permian and Rockies, we expect production to increase a bit when comparing 2025 to 2024, as well as between the second half and the first half of the year. Specifically for the Permian, we anticipate an uptick in production in the latter half of the year compared to the first half. You correctly noted that we have a larger portfolio of secondary benches now. The advantage here is part of our strategy involves reusing existing infrastructure, allowing us to optimize production processing equipment for better returns. This is significant. The changes in oil cut are a result of the mix of wells we are drilling, and our efficiency in drilling and completions can affect our production outlook. Those are the main factors at play. As you mentioned, we do expect oil cut to stabilize and potentially increase in the second half of the year.

Great. And then as a follow-up in the Permian, there's been a lot of industry discussion around water handling and disposal in the basin as you're a very large player. I'm just curious how you guys are looking at that business? Any constraints that might be on the horizon? And any opportunities that you may see to further reduce your cost on the waterfront, especially as you develop these secondary zones, which I think, in some cases, tend to carry a higher water cut?

That's a great question. There are a couple of points to consider. Firstly, regarding well placement, we've excelled in optimizing oil production over water. This approach has significantly boosted our well performance, which has consistently surpassed industry standards. Additionally, our partnerships, particularly with Western Midstream, have enabled us to be proactive about takeaway strategies over the past few years. Lastly, our advancements in technology, particularly in recycling and other areas, are expected to play a crucial role moving forward. While we've focused on the Midland Basin, we've also made substantial progress in the Delaware Basin, which was another benefit brought into our portfolio by CrownRock. It's crucial to monitor these developments, and I believe we are well-positioned to maintain our cost structure while effectively managing water resources in the future.

The next question comes from Scott Gruber with Citigroup.

Yes. I want to dig into the EOR opportunity a bit more. You have a lot of EOR experience in conventional oil, but shale EOR in the evaluation phase for a number of years. Is shale EOR economically viable now at current crude prices and with the 45Q enhancement? Is it really just the CO2 availability constraint that needs to be addressed? And if it is economically viable, just some thoughts on the potential timing of a commercial shale EOR project?

For us, it's really more about having enough CO2 available, which is why direct air capture (DAC) is crucial for our operations. Looking at point source capture to transport CO2 to the Permian is also important, and we are actively preparing for this. Currently, conventional CO2 floods are consuming nearly all the CO2 we can obtain reasonably for the duration of those floods. Therefore, it will take some time to implement the shale CO2 projects. However, when they do happen, they will be economical, and our teams are gearing up for a project in the Delaware Basin, which we aim to launch within the next one to two years. We have conducted sufficient modeling and four pilot projects, with results better than our initial models, prompting us to adjust our expectations. We are confident it will work; it simply depends on obtaining additional CO2. In Oman, we have also tested some reservoirs in North Oman, and CO2 Enhanced Oil Recovery performed well there, making it another location where we hope to utilize DAC or net power. As you know, net power not only generates electricity to operate the equipment but also produces CO2 as a byproduct—pure CO2 that can be used in enhanced oil recovery. We would like to implement that in both Oman and the Permian.

And then turning to a second potential DAC facility in South Texas, does the potential JV and contribution from XRG tilt you towards sanctioning that project, if you could work through the details or would you look to forward sell a certain percentage of the volumes? Just some thoughts on the factors that could impact your decision to sanction a second facility?

Well, we intend to go with the second facility. We have a DOE grant for that as well. So that's going to be helpful. But we do intend to FID. The timing is not set yet, but we will FID it. We're going to take advantage of some of the innovations that are being developed right now on carbon engineering to make sure that we get that in the second facility, just like we're getting in Phase 2 of the current facility. But we will FID. We've got a lot of interest in others that want to be a part of that and a lot of interest in the sales. And we presold the credits for STRATOS and so we'll presale for that one too, but probably not sign contracts until we've done the FID.

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 just want to thank you all for joining our call and for your questions, and have a great day. Bye.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.