Good afternoon, everyone, and welcome to Occidental's Fourth Quarter 2024 Earnings Conference Call. The operator provided instructions on how to participate in the question-and-answer session. Please also note today's event is being recorded. At this time, I'd like to turn the floor over to Jordan Tanner, Vice President of Investor Relations. Please go ahead.

Thank you, Jamie. Good afternoon, everyone, and thank you for participating in Occidental's Fourth Quarter 2024 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 will 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. 2024 was a year of strategic execution for Oxy. We positioned the portfolio to maximize value by increasing our exposure in short-cycle, high-return assets, while also advancing major projects aimed at delivering sustainable returns through the cycle. Our team's relentless focus on performance and commitment to safe and reliable operations enabled us to progress our cash flow priorities delivering on our near-term deleveraging targets while growing value for our shareholders. I'll begin today by covering our 2024 financial and operational achievements as well as our strategic advancements that will position us for success in the years ahead. Then I will discuss our priorities and capital plans for 2025. Sunil will follow with a review of our fourth quarter performance and will provide guidance for the first quarter and the full year ahead. Occidental Petroleum Corporation outperformed across all three segments in 2024, generating $4.9 billion of free cash flow, enabling us to pay approximately $800 million of common dividends. On an organic cash flow basis, we achieved our near-term debt repayment target of $4.5 billion seven months ahead of schedule. Our steadfast commitment to improving our balance sheet is coupled with our drive to invest in our future and generate long-term shareholder value. Capital improvements and operational efficiencies driven by our teams resulted in a capital spend of $6.8 billion, which was the low end of our guidance. Our midstream team also successfully revised key domestic crude transportation contracts to further enhance future cash flows. Now moving to operational excellence. The combination of execution efficiencies along with strong new well deliverability and enhanced base production enabled us to achieve the highest annual US oil production as well as record total company production at 1.33 million BOE per day for Occidental Petroleum Corporation in 2024. This exceeded the upper end of full-year guidance. The US record production was driven by continued well performance leadership across our operated US onshore positions in the Delaware, DJ, Midland, and Powder River Basins. El Hossan contributed to the overall company record. In 2024, our teams reduced lease operating expenses per barrel by approximately 9% and lowered bulk cost by roughly 12% across all unconventional basins. A key differentiator for Occidental Petroleum Corporation is our ability to replace reserves to fortify the long-term sustainability of our business. In 2024, we increased our year-end proved reserve balance to 4.6 billion BOE, which is the highest in Occidental Petroleum Corporation's history. This represents an all-in reserves replacement ratio of 230% for 2024 and an organic reserves replacement ratio of 112%, extending our over 20-year track record of replacing reserves year after year with the exceptions of the downturn in 2015 and the pandemic in 2020. Also notable is that we have been replacing higher-cost production with a higher volume of lower-cost new reserves. Annually, our capital spend for oil and gas development is less than our annual DD&A cost. This is driving increased earnings per barrel and increased earnings per share. In addition, our US onshore inventory continues to get better, which is a testament to our team's dedication to continuous improvement. Even after accounting for wells drilled and divestitures, we increased our operated inventory of US unconventional well locations with sub-sixty dollar breakevens. At the same time, we improved our average well breakeven by 6%. Our OxyChem business also outperformed, exceeding the original guidance midpoint to achieve over $1.1 billion in pre-tax income in 2024. And our midstream segment also performed exceptionally well with our gas marketing optimization efforts offsetting lower in-basin gas performance against our original guidance. Looking back to 2024, we advanced our strategy across all of our businesses. And I want to highlight a few of them. We closed on Crown Rock, adding Midland Basin scale and high-margin inventory, as well as increasing our access to high-quality unconventional oil assets in the US. This is an asset that continues to demonstrate value, with both our financial and production results exceeding expectations. As construction in West Texas moved forward on Stratos, our teams in Squamish, British Columbia, focused on enhancing DAC technology. Some of their innovations are being implemented in Stratos. We believe direct air capture (DAC) will deliver long-term value as well as help achieve US energy security by developing the carbon-neutral fuels the world needs. We have the flexibility to use DAC's CO2 for both enhanced oil recovery and sequestration. And some customers are focused on securing carbon removal credits. Carbon dioxide removals (CDRs) are important to help us prove up the technology and get the cost down. To advance those objectives, we signed several foundational CDR agreements. Last year, we accelerated the pace of DAC R&D through the integration of our Carbon Engineering and Occidental teams, which has resulted in an open exchange of ideas that has expanded our culture of innovation. We are looking forward to bringing these learnings to the development of DAC facilities at the South Texas DAC hub, which was awarded funding from the US Department of Energy. Now I would like to share a few items from our fourth quarter, which demonstrated continued strength in our financial and operational performance to close out a successful year. All three of our business segments also outperformed in the fourth quarter, delivering robust financial returns and generating $1.4 billion in free cash flow. Our OxyChem business generated $280 million in adjusted income, benefiting from better-realized prices and volumes in both the domestic and international markets. Our midstream business outperformed through continued gas marketing optimization during the fourth quarter and from higher sulfur pricing for Al Hosn production. In our Oil and Gas segment, global production during the fourth quarter was 1.46 million BOE per day, outperforming the midpoint of guidance by 13,000 BOE per day and setting a record for Occidental Petroleum Corporation's highest-ever US quarterly production. Our teams ended 2024 with strong performance and momentum going into 2025. Looking to 2025, our strategic priorities reflect an extension of 2024. We remain committed to delivering value to our shareholders and believe strengthening the balance sheet is paramount to achieving this. Our first priority is to continue our deleveraging progress from last year and deliver sustainable dividend growth. Our now $1.2 billion of divestiture proceeds will be used for debt reduction. The savings from the reduced interest payments will be allocated to the dividend as this week our Board of Directors authorized a 9% increase in our common dividend. We recognize the need to balance reducing debt and financial risk today while preserving tomorrow's development opportunities and associated cash flow. To accomplish this, our second priority is to advance our major projects safely and reliably, bringing Stratos online this year and keeping the Battleground modernization and expansion project on track for completion next year. Stratos is progressing on schedule to be commercially operational this year. We completed construction of trains one and two in December and have been thoroughly impressed by the work of our teams and our construction partner, Worley. Construction on the central processing facilities is expected to be completed in the second quarter with commissioning on trains one and two in parallel. Expect startup operations to continue in the third quarter with a ramp-up of the initial capacity through year-end. Our Battleground project is also advancing with completion expected in mid-2026 and commercial operations to begin later that year. The project is expected to increase cash flow through improved margins and higher product volumes, generating a strong return while improving OxyChem's market position for key ingredients used in producing clean drinking water, medicine, and soaps. Our third priority is to maintain our culture of innovation and commitment to operational excellence. Our team's relentless drive for improvement and focus on continuing learning has delivered great results to date, enabling us to outperform targets and deliver more with less. This is most recently demonstrated across the Crown Rock acreage wherein just a few months since close, we have identified numerous opportunities to deliver more production, lower well cost, and accelerate returns. This year, we expect a 10% improvement in time to market compared to last year, and we expect a 7% decrease in well cost which represents a 15% improvement relative to 2023. The teams are continuing to share best practices and innovate through best-of-best workshops which we expect will drive continued efficiency and performance improvements throughout the year. In addition, we see meaningful opportunities to leverage our competitive position, expanded scale, and enhanced capabilities across our full Midland Basin operations. Through the integration, we have identified scale efficiencies, and design improvements with the potential to lower well cost across our remaining Midland Basin program by more than $1 million per well through drilling and completion savings. Reverse synergies were a key driver behind the extension of our Midland Basin JV with Ecopetrol, which will enable additional development of the basin. The agreement further highlights the vital role investment in US oil and notably the Permian plays in the global market. Our teams are also leveraging innovative ideas to unlock greater resources, achieve cost savings, and improve recoveries. Within our Permian operations, we are pushing the technical limits of well deliverability and conducting field trials to further advance deepening reservoir characterization and simulation efforts and enhanced oil recovery in unconventional reservoirs. In our Gulf of America and international portfolio, we are utilizing advanced seismic to uncover new opportunities and provide a rich dataset for AI application. In Algeria, we recently completed the country's largest seismic data acquisition which was also the largest ever onshore acquisition for Occidental Petroleum Corporation. This will play a key role as we look to enhance value through future development. We also have an ambitious set of artificial intelligence initiatives ongoing to maximize value and improve margins. Our Gulf of America operations are utilizing AI to improve supply management, asset integrity, and reservoir characterization. Additionally, we created an AI center of excellence to align all intercompany AI initiatives and accelerate business value. Within our DLE portfolio, we are also at the forefront of direct lithium extraction technology. Working with our JV partner, we are progressing from a pilot to a demonstration plant to explore the commerciality of our subsidiary Terralithium's patented DLE technology. Turning now to our 2025 capital plan. We aim to maximize cash flow by investing primarily in short-cycle high-return assets while making measured investments to advance our mid-cycle projects to provide future cash flow resilience. This year, we plan to invest between $7 billion and $7.2 billion in our energy and chemicals business. The oil and gas capital program is roughly equivalent to 2024 when adjusting for a full year of Crown Rock in our portfolio. Expect full-year production to average approximately 1.42 million BOE per day. This represents relatively stable production from 2024 when accounting for a full year of Crown Rock, with modest oil growth. Similar to years past, we anticipate production in the first quarter to reflect a low point for the year with a significant uplift expected from the second half. Sunil will provide more detail on this in our 2025 guidance. Investments in OxyChem are expected to increase to $900 million this year with 2025 representing the peak year for construction at Battleground. Battleground spend is expected to decrease substantially as the project nears completion in 2026, with OxyChem's capital reverting to maintenance levels the following year. The increase in Battleground spend is largely offset by a decrease in our DLE spend in 2025. We have set it at approximately $450 million. The majority of this capital will be for the continued build-out of Stratos with the remainder directed towards our South Texas DAC hub and Gulf Coast sequestration projects. We built our 2025 capital plan to focus on projects that we believe best position Occidental Petroleum Corporation for long-term success. As in past years, we have retained a high degree of flexibility with more than 75% of our oil and gas capital allocated to our US onshore portfolio. This allows us to adapt to commodity price fluctuations efficiently and respond to market conditions. In addition, our focus on short-cycle, high-return, unconventional development will help to facilitate our near-term debt reduction supporting our cash flow priorities and commitment to enhanced shareholder returns. Now I will turn the call over to Sunil.

Thank you, Vicki. I will begin today by reviewing our fourth quarter results. We announced an adjusted profit of $0.80 per diluted share and a reported loss of $0.32 per diluted share. The difference was primarily due to an increase in long-term environmental remediation liability based on a recent unfavorable federal court ruling. We have appealed the ruling and will seek cost recovery from all potentially responsible parties. Annual remediation and potential cash outlay are not expected to materially increase over the next several years and are expected to extend over multiple decades. Our fourth quarter financial and operational outperformance delivered a strong close to the year with all three business segments exceeding guidance. We generated approximately $1.4 billion of free cash flow, benefiting from higher global production volumes despite lower realized oil prices. As Vicki mentioned, our US portfolio achieved record quarterly production driven largely by high operability and improved well performance across the Delaware and Midland basins. New well performance in our operated Rockies assets also exceeded expectations. Together, this more than offset lower production volumes from our domestic offshore and international assets due to respective weather events and PSL-related impacts. Notably, our 2024 production was achieved with less capital coming in at the low end of guidance. We had a positive working capital change in the quarter, primarily due to the timing of interest payments, impacts from lower oil prices, and fewer barrels on the water at year-end. This, together with our strong operational performance and disciplined capital program, enabled us to exit the quarter with over $2.1 billion of unrestricted cash after repaying $500 million of debt. Now turning to our business plan and guidance. Total capital for the year is expected to be between $7.4 billion and $7.6 billion with investment front-weighted to the first half of the year. Our capital plan represents a strategic mix of investments balancing short-cycle, high-return assets with investments in no-decline non-oil and gas projects, to provide diversification and cash flow stability. Our capital weighting towards a higher proportion of short-cycle US onshore assets will enable significant cash flow velocity that can be applied to debt reduction. It will also allow us to retain significant flexibility to respond to changing market conditions. In 2025, we expect full-year production to average approximately 1.42 million BOE per day, representing mid-single-digit growth from 2024. After adjusting for a full year of Crown Rock, total production volumes are expected to remain relatively flat, though with a nearly 3% increase in oil volumes. As was the case in 2024, our first-quarter production is expected to decrease from the prior quarter due to reduced fourth-quarter activity levels and a lower working interest in recently drilled wells. Severe winter weather in January also impacted Permian production. In addition, volumes will be impacted by plant maintenance and platform life extension at our offshore assets as well as turnarounds at Al Hosn and Dolphin. While we expect lower volumes during the first half of the year, production is expected to ramp up in the second half. Much of this increase is coming from the Permian, which is expected to grow by more than 15% in 2025, due to a full year of Crown Rock and modest growth across our legacy positions. As Vicki mentioned, our Crown Rock assets continue to outperform and are expected to average over 170,000 BOE per day, representing more than 5% growth. Our guidance for Rockies volumes is lower for 2025, driven by the decision to adjust our gas processing to attain ethane rejection in the DJ Basin. This is expected to increase revenues and improve margins, delivering greater value from our Rockies assets. Additionally, our announced divestiture of non-operated Rockies interest will lower full-year production from the region. When accounting for these items and reduced outside operated activity, our 2025 Rockies production is expected to be essentially flat from last year. Despite AVR maintenance during the first quarter, full-year production in our US offshore portfolio is expected to increase relative to 2024. This, coupled with our growth out of the Permian, is expected to increase our total company oil cut to 52% in 2025. Looking to the chemicals business, OxyChem ended 2024 with a strong operational performance, generating $280 million in adjusted pre-tax income in the fourth quarter and exceeding guidance by $50 million. This was driven by better-than-expected pricing in both the domestic and international markets as global supply disruptions kept prices higher and demand held strong through most of the fourth quarter. OxyChem's first-quarter income is expected to be lower than the prior quarter, primarily due to three short-term events. Our operations were affected by the winter storm in January, which temporarily impacted production and restricted access to the market. We also had an unplanned outage at Ingleside that lasted approximately two weeks. And we are seeing an increase in raw material costs following higher-than-expected ethylene plant outages during the first quarter. These temporary cost pressures should ease early in the second quarter once the ethylene suppliers are back online. For the full year, we expect a slight decrease in OxyChem's earnings and are guiding to a midpoint of $1 billion of pretax income. This is driven in part by the events of the first quarter, forecasted high natural gas prices, and expectations for a slightly oversupplied market for the first half of the year. Following late 2024 domestic capacity additions, rationalizations are expected to occur in the second half, which should help to rebalance the market and improve pricing. Our midstream segment had a strong end to the year, with adjusted pretax income outperforming guidance by $104 million. The bulk of this was due to gas marketing optimization in the Permian, with our teams once again expertly managing market volatility to maximize margins. Higher sulfur prices for Al Hosn also contributed to these earnings. All in, the midstream segment demonstrated exceptional performance throughout the year with adjusted pretax income surpassing the midpoint of our original full-year guidance by approximately $600 million. We expect slightly lower midstream earnings in 2025, as the opportunities for gas transportation optimization narrow with increased takeaway capacity now online. While we may see fewer pricing dislocations and opportunities to capitalize on market spreads, we expect our upstream business to benefit from improved realized prices in the Permian. Reduced opportunities to optimize gas marketing will be partially offset by improvements in our crude marketing out of the Permian. As we mentioned previously, we expect to benefit from the revision of two crude transportation contracts at lower rates this year. One of these will be realized at the end of the first quarter, with the second coming into effect at the end of the third quarter. Given the timing, we expect to see an approximate $200 million benefit this year and expect approximately $400 million in annual savings in 2026.

Turning to our low carbon ventures business.

We are extremely excited about Stratos' progress to date and our expected startup of operations this year. Due to the timing and ramp-up period associated with bringing the first phase online, we are assuming a minimal contribution from Stratos in our midstream guidance. We expect a negative working capital change during the first quarter, which is typical for this time of year, driven by interest payments, property tax, and compensation plan payments. Additionally, there are two upcoming 2024 tax payments as part of the federal disaster relief program following Hurricane Idalia, which will further impact working capital in the first and second quarters of the year. I would like to close today by reiterating our commitment to strengthening our balance sheet, which will position us to generate greater shareholder returns. As Vicki shared at the start, we are pleased to announce that we successfully achieved our near-term debt reduction target by repaying $4.5 billion in 2024. We are continuing this momentum into 2025 and announced $1.2 billion in divestitures in the first quarter. Proceeds from these sales will be applied to 2025 maturities, and excess cash flow after common dividends will be available to further reduce our 2026 and beyond debt maturities. By reducing the amount of cash committed to interest payments today, we will place Occidental Petroleum Corporation in a stronger position to deliver an expanded return of capital program in the future. I will now turn the call back over to Vicki.

Thank you, Sunil. As I shared at the start, 2024 was a pivotal year for Occidental Petroleum Corporation. We strengthened our portfolio, delivered on our near-term deleveraging commitments, and advanced our major growth projects. While we delivered exceptional financial and operational results, what excites me the most is the way our change propelled our business forward. With passion, industry leadership, a continued focus on innovation and learning, and most importantly, a focus on safety underpinned it all. In 2024, our employees achieved the best year of safety performance ever in our history across oil and gas, midstream, and OxyChem. The commitment of our people to safe and sustainable operations is embedded in Occidental Petroleum Corporation's core values and helps enable our long-term success. 2025 will be an exciting year for us. Our technical capabilities and portfolio of assets have never been better. The combination of our three business segments uniquely positions us to capitalize on shared learnings and operational synergies. Bringing Stratos online will be a testament to this and demonstrate the differentiated strategy and compelling value proposition that Occidental Petroleum Corporation brings to the table. With that, we will now open the call for questions. As Jordan mentioned, Richard Jackson and Ken Dillon are here with us today for the Q&A. Ladies and gentlemen, we will now begin the question and answer session. To ask a question, you may press star and then one using a touch-tone telephone. If you are using a speakerphone, we do ask that you please pick up your handset prior to pressing the keys. If you do press star and two, we do also ask that you please limit yourselves to a primary question and one follow-up. If you do have further questions, you may reenter the question queue. Once again, that is by pressing star and one. At this time, we will pause momentarily to assemble the roster.

Our first question today comes from Arun Jayaram from JPMorgan. Please go ahead with your question.

Good afternoon. I wanted to see if you could shed some light on the Gulf of Mexico outlook for 2025. You have perhaps maintenance in one quarter; maybe help us think about how the quarterly trajectory could be in the Gulf and maybe some of the projects that are contributing a little bit of year-over-year growth in 2025 versus 2024.

Thanks, Arun. Yes. Gulf of America has a busy year ahead. As you know, we really want to carry out fabrication maintenance and painting activities in good weather and away from hurricane season. This quarter, we have two platforms going through turnarounds. When they come back on, that will add around sixteen thousand barrels a day. Our drilling activities this year involve six wells. This wedge should add between eighteen to twenty-two thousand barrels a day for the year. Our production engineering activities, including stimulation along with optimization work, should add another four to seven thousand BOE per day, and we will carry out a platform turnaround in Q4. So racking these up, including some decline, gets us to a range of 141,000 to 150,000 barrels a day for the year. Opportunistic work may move some things around a bit, but I hope this gives you a real feel for the year. Also, our equipment uptime is top tier, at record levels. In addition to these activities, we are also commencing our Gulf of America 2.0 project, which will add material quantities of low F&D cost barrels. A lot of the capital early this year is focused on Horn Mountain 2.0, and that includes the start of our water floods there and artificial lift projects, which include ESPs and gas lift. So yes, a busy year ahead, but we've got great assets, and we've got a really great team there.

Great. This is super helpful. Thanks for the detail. You mentioned that you've announced, I think in early February, an extension to the Ecopetrol JV in the Midland Basin. Can you just give us some of the basic terms of the agreement and just confirm that this is fully baked into your 2025 guide?

The terms are similar to what we had before. This will be a project that's not huge, but it is an extension in the next year. We will drill about twenty-three wells or so. I'm looking forward to continuing to work with Ecopetrol to get that done. Yes, it is included in our 2025 plan.

Great. Thanks a lot.

Our next question comes from Betty Jiang from Barclays. Please go ahead with your question.

Great. Thank you for taking my question. I want to ask about the Rockies program in 2025, and how you see that developing and evolving over the next few years. We did notice based on the presentation that the activity level is much lower both on a gross and net basis year on year, and CapEx is flattish. Are there any nonproductive capital items in there? Does that impact 2026 and beyond? How should we be thinking about that program going forward? Thanks.

Yeah. Great. Thank you for the question. I'll walk through a few pieces of that. As you noted, part of it is walking through some of the adjustments, especially if you're thinking about production as we step down with the ethane rejection in the first quarter and then working through our announced divestitures. From an activity standpoint, the Rockies has embedded efficiency. Across all of our assets, we've highlighted improved drilling cost and drilling efficiency, and that's true for the Rockies as well. So they're close to a 10% decline looking at really just more efficiency across their drilling and completion activities. That is offset by infrastructure. That infrastructure for us is an important development in the DJ Basin. This is moving to a larger, more contiguous development area that we talked about in the past called Bronco. For us, that gives us about 140 locations at less than $50 breakeven that we'll be able to prosecute over the next three years. While we're trading a bit of that short-term efficiency for the investment and infrastructure in the story, it plays out similarly in the Permian as well. We think that's really value-added spend for us this year. From an activity standpoint, another thing to note is Powder River Basin had some really strong well results. We're continuing to monitor those in the first quarter, and then we'll be set to resume activity in the Powder River Basin in the second half of this year into what we believe will be a very competitive program opportunity for us next year as we contemplate capital.

That's helpful. Thank you. My follow-up is on debt reduction. You guys have made really strong headway on the debt reduction in 2024 and latest in 1Q with the non-core asset sale. There's that $15 billion net debt target still out there. Do you still feel good about reaching that level by late 2026 or early 2027? Obviously, commodity price is a factor, but just wanted to get your sense on that trajectory to that number.

We do still feel comfortable with that. I would say that it's probably more like the first part of 2027, but we feel comfortable with where we are and still have opportunities to supplement our cash flow from operations to help accomplish that.

Our next question comes from Neil Dingmann from Truist Securities. Please go ahead with your question.

Thanks for the time. First question, Vicki, around your 2025 guide—specifically the roughly 1.42 million BOE per day production and around the $7.4–$7.6 billion capital. What type of service cost assumptions are you assuming in there and how much operational efficiency are you expecting? You've certainly continued to see performance gains in both your DJ and Permian areas. I'm wondering if you expect more.

I'll start and Ken will add a bit as needed. Last year was a very strong year from our drilling and completion teams. We delivered about a 12% improvement against 2023 in our drilling and completion cost. That was about half what we call scope and performance. So that's really operational efficiencies, well designs, continuing to improve on those. The other roughly half of that was the market or deflationary factors across our services. For 2025, we're looking at around a 7% drilling and completion cost improvement. There's uncertainty in service costs, but we're really focused on continuing to deliver the performance component of that 7%. That comes from efficiency across both our drilling and completion activities, lower NPT or non-productive time, and improved pad design leading to better outcomes in terms of production for lower cost. Those two things again roll into our seven percent for the year on D&C cost.

Great details. And then just a second quick one on M&A specifically. Vicki, I'd love to hear your thoughts—do you think most of the higher-quality domestic assets have now transacted? If so, would you consider boosting international M&A, or what are your thoughts?

I think we like the international assets that we have today. We intentionally chose these assets. Algeria has incredible reservoirs, and we still have opportunities for not only expansion of the operations that we have today, but exploration as well. Algeria is definitely in our future for growth. Also in Oman, we have opportunities with the continued development of oil. We also have some gas opportunities in Oman that could turn out to be beneficial for us. We're doing a bit of exploration in Abu Dhabi to see how that will turn out. Those reservoirs there are very similar to what we developed in Oman, so we're the right fit to take those blocks. That is going well so far. We will pursue growth in our international projects over the next three to five years, and also in the Gulf of America where the AI work will help unlock complexities, improving exploration success and field development and helping with some of the water flooding projects that Ken has planned. So we like where we are and will continue to grow the positions we already have internationally.

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

Thank you. Good morning. Vicki/Rich, did I get it right that you expect the Permian oil cut to be higher in 2025 versus 2024? If that is correct, what would drive up the oil cut there?

Hi, Paul. A couple of things to think about when we talk about oil cut in the Permian. First, it correlates well with our unconventional growth, so whether it's year-on-year or quarter-on-quarter, oil cut will track that. The other thing that's happened over the last year is Crown Rock coming in. Midland Basin has a different oil cut than the Delaware, and that mix participates. Another factor is our secondary benches, which have been more prevalent in our Delaware position where we've seen an increase with our secondary benches as a mix of our overall program. That increases value even if some metrics are a bit lower. As you watch us quarter on quarter, year on year, those are generally the variables that drive it. We are seeing better oil cut as we go from fourth quarter into the first quarter, and then for the total year 2025 we're improving almost a percent as we look at full year versus 2024. That growth really tracks our production in our unconventional business in the US and our Permian development.

Just to clarify, what I mentioned in my prepared remarks was the growth from the Permian, which Richard just outlined, along with the growth in Gulf of America, which Ken went through. So we said the total company oil cut is going to increase to 52% in 2025.

What percent of your 2025 program in the Permian is on the secondary benches versus 2024? You mentioned secondary benches are better—can you give a sense of the oil cut for those secondary benches?

For this year, total Permian unconventional development—we are up year-on-year in primary benches because of Crown Rock. In the Delaware, we're up about 30% in terms of secondary benches as a percentage of our total program versus last year, which was around 25%. One of the details we've provided in prior calls is that when we say better, those secondary benches are flowing into existing facilities. From a total cost per barrel perspective for the year, you're coming out much more advantaged. You can double or even triple your returns when you're developing with that kind of facilities benefit. As we make investments into new areas and the 140 wells in the Rockies that we're adding with infrastructure investment, we'll see the same play out on total returns for the life of the program.

Our next question comes from Roger Read from Wells Fargo. Please go ahead with your question.

Thanks. Maybe just to quickly come back to the drilling and completion efficiencies. You spelled out a 7% well cost decline this year, and then you expect to save $1 million per well across the remaining program. What is the timeframe on that $1 million per well? Is that built into 2025, or is that spread out over multiple years?

Hi, Roger. That $1 million was specific to our Midland Basin activity, and that was a benefit coming out of the Crown Rock integration with our legacy Midland Basin team. That $1 million was reflected in our fourth quarter drilling and completion costs—it was about $1 million better than our total year 2024 average. We expect that benefit to continue into 2025. Those were real things identified from well design into operational sequencing that came out of that exercise, and they're helping our overall Midland team as well.

Okay. And on a different topic, with the Stratos startup—this is a brand-new technology at scale. What are the main hurdles or milestones we should be watching as you turn this thing on, commission, and ramp it up this year? I understand not to build much profitability into 2025, but what will make you feel comfortable as you go through commissioning and ramp?

It's Ken. I'll go through where we are and then talk through the next steps. We're all really excited. Stratos phase one is at 94% complete overall and 98% complete on construction. Last piping spools are being hydrotested, instrumentation and electric equipment checks are ongoing—getting very close. Worley has done incredibly well on the project. Once we have mechanical completion for the process area, we're moving into the startup phase. The OxyChem teams who have been handling these chemicals for decades are preparing the subsystems and process systems. The sequence is as follows: we'll start pumping water around the system and start running the fans. We've already had a fan running, which was a good day at site. Then we'll start injecting water into one bay, and then mixing potassium hydroxide and the lime. Then we'll start making pellets. Once we start making pellets, we filter those pellets, we dry them, and then we start moving them through the mechanical handling systems to the calciner. Start up the calciner and then start capturing CO2, which is a really big day at site. It'll be very small volumes at first. As with all of our projects, we're looking for opportunities to reduce operating expense and increase capacity. We want to be thoughtful over the next six months to learn as much as we can because the goal is maximizing both of those outcomes over the next several years. So that's what we'll be watching as we bring Stratos online.

I appreciate that. It'll be exciting to watch. Thanks.

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

Thanks for all the information. Just a couple of midstream questions. The guide looks a bit weaker in midstream for 2025 compared to 2024, and then it builds through the year. What's driving that, and what are the variables going into that?

If you look at guidance for 2025 compared to 2024, there are multiple moving pieces. First, on the crude marketing side, we're going to get a lower transportation cost. As I mentioned, there are two transportation contracts that are expiring this year: one in Q1 and the other in Q3. This year we'll get a benefit of around $200 million; next year it's about $400 million. Some of that is partially offset by the annual FERC escalation of around 3%. On the gas marketing side, with additional takeaway capacity coming online from the Permian, we expect narrower differentials between Permian and Gulf Coast, reducing optimization opportunities. On the Al Hosn side, we are seeing higher sulfur prices, which should improve results versus last year. Also, we sold 19.5 million units last year in West, which impacts our income—lower distribution and lower income compared to last year. And on Stratos, the startup and ramp-up will have a small negative impact on income compared to last year. Overall, our midstream team is well positioned to capture value when the market presents itself, and they demonstrated that by beating guidance last year.

Appreciate that. As a follow-up, on the West monetization framework—how are you thinking about the pluses and minuses as you think about deleveraging targets? Also, how should we think about the tax component in that equation?

We continually look at opportunities and evaluate them. It comes down to the value proposition. The tax impact would be part of that value proposition when we're looking at selling and investing in things that provide significant cash flow, as West does. That tax impact would be part of what we consider in our decision-making.

Our next question comes from Doug Leggett from Wolfe Research. Please go ahead with your question. The caller is on for Doug Leggett—please go ahead.

Hi. This is John Abbott on for Doug Leggett. Thank you for taking our questions. First question is on the Gulf of America: can you talk about visibility beyond 2025 and how you see sustainable production?

Sure. We intend to have a goal of staying relatively flat long term. If you look at the projects we're working on—primary development drilling programs, exploration wells, and then the EOR and Gulf of America 2.0 projects—the water floods carry very low F&D and very low decline and are long-term. These are pressure maintenance projects rather than pattern water floods, so they don't require huge drilling overheads on existing facilities. We have unconventional opportunities and refracturing opportunities. The scale of the opportunity in the Gulf is hundreds of millions of barrels potentially, and we've mapped out the Gulf of America 2.0 projects and are working through them. So long-term sustainability is the goal, with many projects accreting to lower costs and long-term production stability.

I share Ken's enthusiasm about the Gulf of America. Over the out-years, three to five years, it will be an important part of our growth story.

Appreciate it. Second question on your EOR business—you no longer break out production in your financials; could you provide an update where production stands? Is it still around 140,000 barrels per day, which was your run rate a couple of years ago?

Thanks for the question. Regarding enhanced oil recovery production, the production level is similar and there has been some slight decline over the last three years. Capital investment has been a bit lower the last several years. That business has delivered great efficiency on cost, and when we talk about operating expense reductions, they have led the way. EOR is leveraged more to OPEX than capex, and that helps deliver good cash margin to our business. In the future, this is part of our strategy with CO2 and carbon capture, and as we get lower-cost CO2, we're excited about what that business can become—very low F&D cost barrels at low decline rates. When we bring that production on, it will provide nice cash flow attributes to complement the rest of our business.

Our next question comes from Leo Mariani from Roth. Please go ahead with your question.

I wanted to ask a general question around the low carbon ventures business. With the significant change in the administration in the US, are you thinking about that business differently over the next four years as you proceed to prosecute projects?

Not really. We are aware of the situation and there's more uncertainty around 45Q and federal support, but our view is that CO2 will be much needed for the US. The shale revolution was an amazing thing for the United States. We believe the next round of technology that will add significant barrels—on the order of 50 to 70 billion barrels of recoverable reserves—will come from enhanced oil recovery using CO2. There is not enough organic CO2 in the country to flood all the reservoirs that would benefit, so direct air capture to obtain CO2 is needed. That will extend energy independence materially. Direct air capture is a technology that needs to work for the United States. I have had several conversations with members of the new administration and people around them who understand the needs for at least some initial subsidies to help advance this technology, just as transformational technologies often had some assistance at the beginning. We believe we have the capability to get the cost down on DAC facilities. We're very impressed with the combination of the Occidental and Carbon Engineering teams; the innovation is occurring rapidly and is very helpful. To get where we need to be, 45Q is important. We are talking with members of Congress and senators and have met with many of the new cabinet members. We're getting the story out that DAC is needed for the next phase of US energy development. Even if government support is not exactly as expected, I believe we can move the technology down the cost curve faster than initially planned, and that is where we're headed with Stratos and the King Ranch DAC facility.

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

I'd just like to say thank you all for your questions and for joining our call. Hope you have a great rest of your day.

Thank you. The conference has now concluded. We do thank you for attending today's session. You may now disconnect your line.