Occidental Petroleum - Earnings Call - Q2 2025

Executive Summary

• Adjusted EPS of $0.39 beat Wall Street consensus $0.31; revenue of $6.41B was modestly above $6.33B; EBITDA was slightly below consensus ($2.86B vs $2.93B). The beat was driven by higher volumes and LOE efficiencies, partially offset by lower realized commodity prices. EPS/Revenue estimates from S&P Global: $0.31 EPS, $6.33B revenue, $2.93B EBITDA; actuals $0.39/$6.41B/$2.86B*.
• Sequentially, revenue fell (~6%) as realized oil/NGL/gas prices declined; adjusted EPS dropped from $0.87 to $0.39; production was 1,400 Mboed, above guidance mid-point, with Permian 770 Mboed.
• Guidance: Raised full-year Midstream & Marketing by $85M; lowered OxyChem full-year pretax income to $800–$900M; reduced 2025 capital guidance mid-point by $100M and international OpEx by $50M; guiding Q3 production to 1,420–1,460 Mboed.
• Strategic catalysts: $950M divestitures since Q2 start and ~$$7.5B$$ debt repaid since July 2024; STRATOS (DAC) on track to begin CO2 capture in 2025 with new CDR agreements (JPMorgan and Palo Alto Networks).

What Went Well and What Went Wrong

• What Went Well
  • Operational efficiency: Domestic LOE outperformed at $8.55/boe, supported by automation, sensors, and AI; Permian well costs down ~13% YTD vs 2024.
  • Volumes: Total production 1,400 Mboed above guidance mid-point; Permian 770, Rockies 272, Gulf 125, International 233 Mboed.
  • Midstream upside: Segment exceeded high-end of guidance (crude/gas marketing optimization, higher sulfur prices), and full-year guidance raised by $85M.
  • Management quote: “We’re on track to start capturing CO2 this year… the majority of volumes through 2030 from Stratos are now contracted” — Vicki Hollub.
• What Went Wrong
  • Price headwinds: Average realized prices fell QoQ — crude -10% ($63.76/bbl), NGL -20% ($20.71/bbl), domestic gas -45% ($1.33/mcf), pressuring earnings.
  • OxyChem weakness: Pretax income below guidance on weaker caustic/PVC pricing; full-year guidance cut to $800–$900M.
  • Gulf of America curtailments: Third-party constraints and schedule delays reduced sales volumes; earnings considerations flagged 125 Mboed in Q2.

Transcript

Speaker 8

Please note this event is being recorded. I would now like to turn the conference over to Jordan Tanner, Vice President of Investor Relations. Please go ahead.

Speaker 7

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, 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 Investor 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.

Speaker 0

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. 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 strengthened 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 in less than a year from closing the Crown Rock 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 Mexico. 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 Crown Rock, as well as some production growth from Legacy Oxy. 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 costs 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 costs 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 operator routes, we have transitioned approximately 40% of our onshore production to route-less operations.

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're 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 costs 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 Crown Rock 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 cost compared to 2024. The capital efficiencies, along with continued improvements and 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 Mexico, with one of the best at Horn Mountain in 22 years and the best at Caesar Tonga in 13 years.

Both are on production now 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 low-carbon ventures business. In just two years since groundbreaking, Stratos has achieved a significant milestone with trains one and two 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 towards 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 Center into phase two. 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've 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 and 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 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 emissions 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 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 emissions 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 Crown Rock 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.

Speaker 6

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 a 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 barrel 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 fully oil prices compared to original expectations. We are guiding to an adjusted effective tax rate of approximately 32% for the third quarter, with our fully 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 Mexico. 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 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 Mexico, 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 Mexico. This modified production mix is expected to slightly reduce annual total company oil cuts. As Vicki shared, our Midstream and 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 Lozan during the quarter. Given the strong second quarter performance, we have raised full-year Midstream and 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 will be prepared for any marketing optimization opportunities as they arise. 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 pre-tax 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 and EOR parity, 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 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 deductibles. 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 Crown Rock 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 Crown Rock 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.

Speaker 0

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. 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.

Speaker 8

We will now begin the question and answer session. To ask a question, you may press star, then one on your touch-tone phone. If you are using a speaker phone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then two. Please limit questions to one primary question and one follow-up. If you have further questions, you may re-enter the question queue. At this time, we will pause momentarily to assemble our roster. The first question comes from Arun Jayaram with JPMorgan. Please go ahead.

Yeah, good afternoon. 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 to $800 million of tailwinds. I think you said 35% in 2025 and the balance in 2026. Is that correct? Maybe help us think about what that would translate into a cash tax rate, perhaps in 2026.

Speaker 6

Hi, Arun. Firstly, that is correct. 35% of the $700 to $800 million benefit will be in 2025, and the balance is going to be in 2026. The way 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 purpose. You can go based on the guidance in terms of the book tax rate, but what you're going to see is the difference in the deferred tax expense increasing due to this benefit.

Speaker 8

The next question comes from Douglas George Blyth Leggate with Wolf Research. Please go ahead.

Thank you for taking my question, guys. 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 over through 2050. I recall that there are significant cost recovery benefits from stepping back up the spending. 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.

Speaker 0

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

Speaker 2

Yeah, afternoon, Doug. 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 is you look back to the days that you mentioned. Since then, we've produced 640 million barrels to date. Originally, it was very focused on the steam floods. With all the work we've done there, what we see is multiple stacked bays across a very large block. In the north, we've been producing the Laylett Wells for some time now, which are totally different and don't need any steam.

We see the extension as a win-win for Oxy and the government and sustainable. As Sunil said on the last call, you'll see the numbers rolling through the books over time.

Speaker 0

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 we be limited to one, or can I have a follow-up?

Do you have a follow-up?

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

Another thing that we have is we have scattered acreage that goes all the way from here through the Rockies and into even the Virginias. We have a lot of acreage because of the acquisitions that have been made over time to create what we have today. A lot of that has not a lot of value, but needs to be cleaned up, accumulated, and sold. At some point, we'll sell that. Those would not be big dollars, though. Currently, I think the team is working on rounding that up and getting that ready for sale.

Speaker 8

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

Hi, good afternoon. Thank you for taking my question. Vicki, just given your comment about OBB's benefit on 45Q and the carbon business, I was wondering if that changes your strategic focus around the carbon business towards potentially more point source opportunities for EOR purposes, just given that you are the utilization parity you mentioned.

Speaker 0

Yeah, we've always been interested in point source capture. In fact, that's what kicked off our desire to get and then to make the technology of direct air capture better. Because since 2008, from about 2008 until we found direct air capture, we were trying to get point source capture. Back then, the carbon credits for that kind of capture were so low that we couldn't convince any industry to do it. Now, with the parity for CO2 enhanced oil recovery, we've never given up on that effort. We've continued that, and we'll continue looking for point source. There's quite a bit of emissions that are within pipelines that could be gotten, that could get the CO2 to the Permian. We'll still be working that. What I'm hoping this will do is it'll make the industrial sources of CO2 more willing to work out an arrangement with us.

It's Betty, just one quick one. This is Richard to add. I would say one sort of tailwind that's helping is natural gas, the power generation, especially in places like the Permian. 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.

Got it. That makes sense. It's very impactful for the EOR business for sure. My follow-up on actually back to cash taxes. What will be the cash tax saving potential beyond 2027? Do you go back to where it was before, or you continue to expect savings?

Speaker 6

Beyond 2026, it will depend on the capital trajectory and the proportion of domestic spending. Today, if you look at our capital, around 90% of it is domestic, and we don't expect any significant change in that mix. The reason we highlighted the 2026 estimate is because we have the battleground expansion project that is expected to come online next year. We're expecting more 100% bonus depreciation qualifying assets in 2026 compared to 2025.

Thank you for that color.

Speaker 8

Okay, once again, we'll try again. Arun with JPMorgan, please go ahead with your follow-up question, sir.

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

Speaker 2

Yeah, 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 made recently offshore increase the capacity from our eastern facilities. I think in the central Gulf of Mexico area, as Vicki mentioned at the start of this, we're seeing wells that are coming in with very large EURs. One of them could potentially end up as one of the best Gulf wells we have ever drilled.

I think the combination of the subsurface engineering that's being carried out along with the geoscience, layered onto what we've done over the last three years in terms of getting equipment reliability and availability up, means that we're positioned incredibly well going forward for the production ramp-up.

Speaker 8

The next question comes from Nitin Kumar with Mizuho. Please go ahead.

Good afternoon, everyone, and thanks for taking my questions. 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. 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?

Speaker 0

Yeah, I would say that you're right. Next year, we will have a reduction in our OxyChem spend by about $300 million, 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. Do you want to comment some on that, Richard?

Sure. No, I appreciate the opportunity. The team's done an outstanding job across capital and operating expense. Speaking to the capital, again, like you said, we've another incremental $100 million down this quarter. This is on top of the $100 million in the first quarter, so $200 million below our original plan. For us, we do see opportunities going forward to not only sustain that but continue to improve it. We are having good success. Really, when drilling efficiency, whether that's non-productive time reduction or larger pads, we're moving to from sort of two to three well pads in the first half of the year to four to six. Our completion frac teams continue to deliver efficiency results. As we couple that together, we expect to continue to see that.

As we think about 2026, though, I think we're at a point where we're really working to optimize activity levels for efficiency. While we're not targeting growth, it's really the outcome of what do we need to do to maintain these efficiencies. I think today we're largely near an optimized activity level. We'll watch it over the next several months to see, as things, efficiencies may move, activity continue to the left on our schedule. We'll anticipate that to make sure we have the right bridge into that 2026 activity.

I'd say the other place that we could shift some capital would be to the lower decline, low F&D, high margin water flood projects that can agenda for the Gulf of Mexico. Those are very competitive.

That's a perfect segue to my next question. I appreciate you teaming 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 the Gulf of Mexico this year, what would be a good steady sort of run rate for the Gulf of Mexico, let's say in 2026 and 2027 from a production standpoint? Could you help us bridge the gap from where we are today between new developments, these water floods, et cetera, basic lines, and also return or sort of curtail the constrained production right now?

Speaker 2

Good afternoon. Thanks for the question. I think if we maybe do it in reverse order, you know, operationally, we experienced a mix of things, including pipeline constraints. As Vicki Hollub highlighted, we've also seen incredibly positive results in our wells this year. We modified our pumps in Eastern Gulf of Mexico 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 had been doing work for another operator. These elements have all been built into a 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 of Mexico, it's all about optimization and planning.

Over the last few years, as you know, we've really improved the availability and planned uptime. The next phase of our OpEx optimization is to move to turnarounds every two years. That multi-year schedule is being poured at the moment, including mapping resources internally, externally, and ties to vendors that can service us through the long term. We're considering starting that next year. More information to come on the 2026 plan later this year.

Speaker 8

The next question comes from Neil Mehta with Goldman Sachs. Please go ahead.

Yeah, thanks so much. Looking at slide 34, you talk about advanced subsurface characterization and technological improvements. I think a lot of investors are just wondering what inning are we in terms of digital application in the oil field? How are you employing it? Do you think it's going to fundamentally change the industry and our ability to drive volume?

Speaker 0

We are so excited about what we've been able to do internally within Oxy to start building our AI capabilities. I think we've talked on this on the calls previously about our AI effort in the Gulf of Mexico. 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. 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 two years following. Gulf of Mexico, that's going to be an area 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.

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 Mexico. We have a group that's working the broader challenges of logistics and supply chain and things like that. 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. Just how do you see the U.S. production profile evolving over the next five years?

We believe that the U.S. could hit peak production between 2027 and 2030. We've modeled that based on Hubbard 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. 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 to 70 billion barrels of oil developed by and through CO2 EOR. It is, to us, incredibly important because energy independence for the United States really impacts our ability to maintain our leverage in the world. 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.

CO2, in our experience over the 50 years that we've been doing it, has been able to get more than any other technique that we've tried beyond primary production and water flooding. 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. CO2 EOR will get us double-digit increases from that amount, we believe. The 50 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.

Thanks, Vicki. Appreciate it.

Thank you.

Speaker 8

The next question comes from Paul Cheng with Scotiabank. Please go ahead.

Thank you. Good morning, Vicki, or good afternoon, you guys. 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's constraining the activity level so that you can't do or go a bit faster?

Speaker 0

What has happened with this contract is certainly going to make that project a lot more competitive. There are no restrictions with respect to what we can consider there. The main restriction for us in terms of capital and for the industry itself is right now we have an oversupplied market. In our view, there is no reason for companies to get too aggressive with growth right now. You are just making the problem worse if we do that. For us, we are absolutely determined to get our debt down sooner rather than later. 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.

We are not looking for growth, as Richard had said. We are looking for the activities that can help us continue to optimize, reduce our cost, and lower our cost structure. I can tell you that every one of our asset teams, including midstream and chemicals, works every day to find ways to lower our costs because we believe at the end of the day, it is 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. We are doing it now. We will continue doing it. The next step is to get our DAC cost down to the point where the CO2 cost enables us to generate maximum returns from those CO2 floods.

With respect to Oman in particular, it is ultimately going to be a place where there will be incremental capital. We will just have to figure out when that is going to be. What do you think, Ben?

Speaker 2

Yeah, just one thing to build on what Vicki said. You know, in the same way the U.S. onshore is improving, both in terms of capital efficiency and operational efficiency. In Block 53, our drilling rigs are now running at their lowest cost per foot and their highest feet per day rates ever. In OpEx efficiency, our artificial lift equipment is running at its highest reliability ever, and our workover rigs are performing at their best level ever, all done with the best safety performance and with great help from our teams in the center, also using AI. We are doing more, just doing it much smarter.

It is a combination of the engineering-related activities, but it is also through supply chain also. We are working supply chain around the world, and we are seeing the effects roll through onshore, effects rolling through offshore, and rolling through in our assets around the world. We see more opportunities to come, so a lot more with less also.

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

Speaker 0

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. We will, over time, need to increase our production, but it would be at the appropriate time. 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 said, our portfolio is diverse. We have the high return shale with 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.

Speaker 2

Sure. 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 in the south, it's predominantly heavy oil, but with some lighter oil. In the northwest, it's light oil. In the east, it's gas. We mentioned our Bekia discovery recently. Some of these blocks, we do not have partners. We have opportunities to use partnerships as a way of funding projects also to accelerate things, without digging into our own capital going forward. We have a huge range of options with very low option cost at the moment as we work through things.

Speaker 8

The next question comes from Kevin Moreland MacCurdy with Pickering Energy Partners. Please go ahead.

Hey, good morning. Thanks for taking my question. 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 Chems next year? Just one for me. Thank you.

Speaker 6

In terms of the 2026 market, it's going to a large extent depend on the timing of the supply-demand balance. 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. If you look at the Chinese exports on the PVC side, it's grown from almost nothing in 2020 to almost 30% currently. The same with caustic. It's been increasing and it's still growing. Some of the announced capacity rationalization in Europe and the U.S. will potentially mitigate some of those capacity additions, but we don't see a meaningful impact of that in 2026. We believe that the integrated margins between PVC and caustic are close to the variable cost of many international producers, including China.

We don't anticipate further sustained declines in margins, but as far as 2026 goes, we believe it is more likely to be what we saw in 2025.

Thank you.

Speaker 8

The next question comes from Matthew Merrel Portillo with TPH. Please go ahead.

Good afternoon. 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 on the gas and NGL side. As you look into the back half of this year, especially given the high till count in Q2, do you expect that oil cut to stabilize or even improve a bit into the second half of 2025?

Yeah, great. Appreciate the question. Let me walk through a few pieces of that. I would say overall, U.S. onshore, so if you're looking at Permian plus Rockies, as we think about not only '25 versus '24, but also second half versus first half, we expect that to go up a bit. With respect to the Permian, we do expect an increase in the second half of the year from where we have been in the first half. You got it exactly right. We have much more secondary benches as a part of our portfolio. The good news is, I think you know, as part of our strategy, it's really reusing the infrastructure. Being able to refill existing production processing equipment can deliver exceptional returns. That is a big part of it. Really, the oil cut is an outcome of that well mix. It's drilling completion efficiencies.

As we move production to the left, that can change some of our outlooks. Those are really the variables that change it. As you say, we do expect it to stabilize and actually increase in the second half of the year.

Great. 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 costs on the waterfront, especially as you develop these secondary zones, which I think in some cases tend to carry a higher water cut.

Right. Great question. A couple of aspects to that. I'd almost start with where you said on the secondary benches. I would say one key thing that I think we've done really well, and this is with respect to our well performance, which has continued to outpace really the industry, is thinking about well placement to optimize the oil, not the water. I think we've had great success just from that standpoint, starting in the subsurface. As you think about, as it comes to surface, obviously having the partnerships, having the long sort of connection with Western Midstream and others, thinking about that takeaway, we've tried to be proactive for the last several years looking at that. The final thing I would note is just the technology.

I think we continue to highlight our technology advancements in recycling and others, and we do think that's going to be a meaningful part of the solution going forward. Midland Basin has been a big thing we've highlighted, but we actually do quite a bit in the Delaware Basin as well. It's another synergy that Crown Rock brought into our portfolio as well. You're exactly right. It's a very important thing to watch. I think we're well positioned to maintain our cost structure and really be smart about that water as we go into the future.

The next question comes from Scott Gruber with Citigroup. Please go ahead.

Yes, good afternoon. I want to dig into the EOR opportunity a bit more. You have a lot of EOR experience in conventional oil, but shale EOR has been in the, call it, 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 a CO2 availability constraint that needs to be addressed? If it is economically viable, just some thoughts on potential timing of a commercial shale EOR project. Thank you.

Speaker 0

For us, it's really more about the availability of the CO2. That's why DAC is so important for us. That's why going and looking at point source capture to get it to the Permian is important. We're doing that work and trying to get prepared for it. We have right now, the conventional CO2 floods are taking almost as much CO2 as we can get right now reasonably for the life of the floods. It's going to take a little while for us to make the shale CO2 happen. It is going to be economical. Our teams are getting prepared for a project in the Delaware Basin, and we'll be putting that on within the next probably year to two years. We have modeled it enough. We've done four pilots. We've done the modeling. The pilots were better than the model, so we've recalibrated. We know that it will work.

It's just a matter of getting the incremental CO2. In Oman, we've also tested some reservoirs in North Oman, and CO2 enhanced oil recovery did well there too. That's going to be another place where we'll apply, hopefully, DAC and/or net power. Net power, as you know, it not only generates electricity to run the equipment, but it creates CO2 as a side stream, pure CO2 that can be used in EOR. We'd like to apply that in Oman as well as in the Permian.

That's interesting. It's good to hear. 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 can 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 the decision to sanction a second facility.

We intend to go with the second facility. We have a U.S. Department of Energy grant for that as well, which is going to be helpful. We do intend to FID it. 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 in carbon engineering to make sure that we get that in the second facility, just like we're getting it in phase two of the current facility. 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. We pre-sold the credits for Stratos, and we'll pre-sell for that one too, but probably not sign contracts until we've done the FID.

Speaker 8

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.

Speaker 0

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

Speaker 8

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