Occidental Petroleum Corporation (NYSE:OXY) Q4 2024 Earnings Call Transcript

Occidental Petroleum Corporation (NYSE:OXY) Q4 2024 Earnings Call Transcript February 19, 2025

Operator: Good afternoon, everyone, and welcome to Occidental’s Fourth Quarter 2024 Earnings Conference Call. [Operator Instructions] 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.

Jordan Tanner: 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 Matthew, 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.

Vicki Hollub: 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. An organic cash flow, 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 enhanced base production enabled us to achieve the highest annual US oil production as well as record total coffee 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, TJ, Midland, and Powder River Basins. And El Hozan contributed to the overall company record. In 2024, our teams reduced a mess lease operating expenses per barrel by approximately 9% and lowered bulk cost by roughly 12% across all unconventional bases.

Q&A Session

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 and 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 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 outperformance 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, 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 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 EOR and sequestration.

And some customers are focused on securing carbon removal credits. 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 Petroleum Corporation 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 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 Alhosin 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 Patrol, which will enable additional development of the basin. The agreement further highlights the vital role investment in US oil and most 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 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 LCD portfolio, we are also at the forefront of direct lithium extraction technology. Working with our JV partner, we are progressing from a pilot to demonstration plan 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 Bell Ground. 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 LCD 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 backup 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.

Sunil Mathew: 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 PSE-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 On Mountain as well as turnarounds at Alosin 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 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 Presley 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 Alosin 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.

Vicki Hollub: Turning to our LCV business.

Sunil Mathew: We are extremely excited about Stratus’ 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 Barrel, 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.

Vicki Hollub: 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, and 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. That’s 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 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.

Vicki Hollub: Good afternoon. I wanted to

Arun Jayaram: see if you could shed some light on the Gulf of Mexico outlook for 2025. You have, you know, perhaps maintenance in one queue and 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. Twenty-five versus twenty-four.

Vicki Hollub: Ken, you wanna share our Gulf of America information.

Ken Dillon: Thanks, Arun. Yes. Gulf of Mexico. Gulf of America has a busy year ahead. As you know, we really want to carry out fabric maintenance by the extension and painting activities in good weather and away from hurricane season. So 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 OBO, should add another four to seven thousand BOEs 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 one hundred and forty-one to one hundred and fifty thousand 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, so record levels. And then in addition to these activities, we are also commencing our Gulf of America 2.0 project, which will add material quantities of low F and 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, 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.

Arun Jayaram: Great. This is super helpful. Thanks for the detailed. You mentioned that you’ve announced, I think, in early February an extension to the echo Patrol 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 in your 2025 guide?

Vicki Hollub: Yeah. The terms are similar to what we had before. And this will be a project that’s not huge, but it is an extension in the next year. And we’ll drill about twenty-three wells or so. And I’m looking forward to continuing to work with Ecopetrol to get that done.

Arun Jayaram: Great. Thanks a lot.

Vicki Hollub: Thank you. And our next question comes from Betty Jiang from

Betty Jiang: Barclays. Please go ahead with your question.

Vicki Hollub: Great. Thank you for taking my question. I want to ask

Betty Jiang: about start with the Rockies program in 2025, but also how you see that develop and evolving over the next few years. We did notice based on the presentation that the activity level is much lower both from the gross and net basis year on year, and CapEx is flattish. So just are there any nonproductive capital in there? Does that impact 2026 and beyond? And how should we be thinking about that program going forward? Thanks.

Richard Jackson: Yeah. Great. Thank you for the question. This is Richard. 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 got some embedded efficiency, I’d say, is the first place to start. We’ve across all of our assets, we’ve put in the highlights the improved not only drilling cost but drilling efficiency, and that’s true for the Rockies as well. So they’re close to a hundred million down looking at really just more efficiency across their drilling and completion activities.

That is offset by infrastructure. And 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. And, you know, for us, that gives us about a hundred and forty locations at less than fifty dollar breakeven that we’ll be able to prosecute over the next three years. And so while we’re trading a bit of that efficiency for the investment and infrastructure in the story, plays out a bit in the Permian as well. We think that’s, you know, really value-added spend for us this year. From an activity standpoint, the Rockies is the only other thing I’ll note. Powder River Basin, you know, had some really strong well results. I think we highlighted those over the last couple of quarters in terms of the productivity of those wells.

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.

Betty Jiang: That’s helpful. Thank you. My follow-up is on sort of the debt reduction. You guys have made really strong headways on the debt reduction in 2024 and latest in 1Q with the non-core asset sale. There’s that fifteen billion dollar 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.

Vicki Hollub: We do still feel comfortable with that. I would say that probably it’s gonna be 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. And our next question comes from Neil Dingmann from Truist

Neil Dingmann: Securities. Please go ahead with your question. Thanks for the time. First, my first question, Vicki, is just maybe around your 2025 guide, specifically you’re talking about about a million four BOE per day production in around, what, the seven and a half million CapEx. I’m just wondering on the around those two, what type of service cost are you all assuming in there and, you know, how much operational efficiencies because you certainly have continued to see that, you know, both in your DJ and Permian. I’m just wondering if you expected more.

Vicki Hollub: We’ll pass this to Richard since he gets seventy-five percent of the capital.

Richard Jackson: Sounds good. But I’ll maybe share the answer with Ken a little bit as we talk about service costs. So let me start with the performance. You know, I had noted some of the Rockies improvements, but overall, last year was a very strong year from our drilling and completion teams. We delivered about a twelve percent 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. That was some of the benefit, especially in the Midland Basin that we saw with Crown Rock as we came together as one team. The other roughly half of that was the market or sort of the deflationary factors across our services.

For 2025, we’re looking at around a seven percent drilling completion cost improvement. Obviously, uncertainty a bit in terms of service costs and Ken can help address some of that. But we’re really focused on continuing to deliver the performance component of that seven percent. And so, you know, can get more detail if we get into it, but really just efficiency across, you know, both our drilling and completion activities, lower NPT or non-productive time across those activities. A bit more improved pad design is leading to some better outcomes in terms of production for lower cost. And so those two things again roll into our seven percent for the year on D and C cost.

Neil Dingmann: Great details. And then just a second quick one to on M and A specifically. Vicki, I’d love to hear your thoughts if you know, you think most of the higher quality domestic assets have now transacted. And if so, you know, would that your thoughts around that? Would you now consider, you know, maybe boosting international M and A, or what?

Vicki Hollub: I think we’d 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. So Algeria’s definitely in our future for growth. Also in Oman, we have opportunities with the continued development of oil. But we also had some gas opportunities in Oman that could turn out to be a really good thing for us. We’re doing a little bit of exploration in Abu Dhabi, just to see how that will turn out. Those reservoirs there are very similar to what we developed in Oman, so it was we were the right fit. To take those blocks three and five there in Oman, and that’s going well so far.

So we will start with not only growth in our international projects over the next probably, probably three to five years, but also in the Gulf of America where the AI is not only gonna do things that I described in my script, but also we believe that we’re gonna be able to unlock some of the complexities in the Gulf. And that will turn into not just having better success with exploration but better field development too, and could also help with some of the water flooding projects that Ken has planned. So we’d like where we have and we’re just gonna work on growing the positions that we’re already in internationally.

Paul Cheng: Our next question comes from Paul Cheng from

Vicki Hollub: Scotiabank. Please go ahead with your question.

Paul Cheng: Thank you. Good morning. Vicki, did I get

Richard Jackson: it right that in one of I don’t think it’s yours. Maybe it’s a new prepared remark that you expect the Permian oil cut is going to be higher in 2024 2025. And if that is correct, what would drive up the oil cut over there? That’s the first question.

Richard Jackson: Hi, Paul. This is Richard. I’ll take that one. Just a couple of things to think about when we talk about oil cut in the Permian, and then I’ll get into a bit of the numbers. You know, first of all, it correlates very well with our unconventional growth. So whether it’s year on year or quarter on quarter, you can see that oil cut will track that. The other thing that’s happened over the last year is really Crownrock coming in. And so, Midland Basin obviously has a bit different oil cut than the Delaware, and so that mix participates. The other factor I’d like to talk about in the Permian is just our secondary benches, and that’s been more prevalent in our Delaware position where we’ve seen an increase with our secondary benches as a mix of our overall program, which as we talked about, delivers better value even with a bit lower.

So, you know, as you watch us sort of quarter on quarter, year on year, those are generally the variables that drive it. Now to address your question, yes, we are seeing better oil cut even as we go fourth quarter in the first quarter. And then total year twenty-five were improving almost a percent as we look at full year versus twenty-five. So again, that’s growth that’s really tracking our production in our unconventional business in the US, Permian development.

Paul Cheng: And which one? Just to

Sunil Mathew: sorry. Just to clarify, what I’d mentioned in my prepared remarks was the growth from Permian, which Richard just outlined, along with the growth in Gulf of America, which Ken went through the details. So we said the total company oil cut is gonna increase to fifty-two percent in 2025. Just wanted to clarify on that point.

Paul Cheng: Yes. Thank you, Sunil. Rich, what percent of your 2025 program in the Permian is on the secondary branches versus the 2024? And you’re saying that the per the secondary branches is better. So can you give us a what is the oil cut in those secondary benches? Thank you.

Richard Jackson: Yeah. Yes. Perfect. For this year, total one thing to think about. Total Permian unconventional development, we talk about primary benches. Are actually up year on year, and that’s because of our Crown Rock development and our very derisked and provide a lot of primary benches. In the Delaware, this year, we’re up about thirty percent in terms of secondary benches as a percentage of our total program versus last year was around twenty-five percent. And what I you know, one of the details we provided in prior calls or talked about is when we say better, those secondary benches are flowing into existing facilities. And so from a total cost per barrel for the year, you’re coming out much more advantage. You can double or even triple your return when you’re looking at a development program with that sort of benefit coming from facilities.

So I talked about, you know, this year as we make these investments into these new areas and the one hundred and forty wells in the Rockies that we’re adding with that infrastructure investment. We’ll see that same play out on total returns for the life of the program.

Roger Read: Our next question comes from Roger Read

Vicki Hollub: from Wells Fargo. Please go ahead with your question.

Roger Read: Yeah. Thanks. Good more or

Vicki Hollub: good afternoon. What am I talking about here?

Roger Read: Maybe just to quickly come back to

Vicki Hollub: the question on drilling and completion efficiencies on I guess, slide thirteen, the spelled out the well cost declines this year seven percent, and then there is expect to save one million per well across remaining program. What is the I’m assuming the million’s strung out over a longer period of time, but I just wanted to get little clarity on maybe two different lines of banking.

Richard Jackson: Yeah. Hi. Hi, Roger. Good afternoon. That one million dollars was specific to our Midland Basin activity, and that was exciting to us because that was really a benefit coming out of the joint Crown Rock or Oxi Rock team with our legacy Midland Basin team. And so that one million dollars was really, you know, delivered in the fourth quarter. We looked at our fourth quarter drilling completion costs it was one million dollars better than our total year 2024. We expect that to continue now into 2025. And so, you know, quite a few really strong things that were identified from well designed into operational sequencing that came out of that exercise. So, you know, we talk about the benefits and, you know, cash flow delivery from our Oxy Rock assets and team, but it’s also helping our overall Midland team as well.

Roger Read: Okay. Gotcha. So just sort of built in, doesn’t

Richard Jackson: things we see and we’ll see, but not a not a separate goal going forward.

Roger Read: No. The Disgusting. Correct.

Roger Read: And then to change pace just a little bit here with

Vicki Hollub: the Stratus startup, given you know, this is a very I wanna say, brand new technology, but it’s a brand new at scale, you know, commercial system. What are the

Roger Read: main

Vicki Hollub: I don’t know if you wanna call them, you know, hurdles or milestones or whatever we should be watching as you turn this thing on, ramp it up, commission it, this year. Understand not to build any real profitability in, but what are you looking at as key challenges that will make you feel more comfortable as you go through the commissioning process?

Ken Dillon: Hi there. It’s Ken. Just to go through where we are and then talk through the next step. So I think we’re all really excited here. Stratos phase one is at ninety-four percent complete overall and ninety-eight percent complete on construction. Last piping spills are being hydro tested, instrumentation and electric equipment checks are ongoing. So getting very close. And as Vicki said, Worley has done incredibly well on the project. In terms of so once we’ve got the mechanical completion for the process area and the count signer, we’re then moving into the startup phase. In terms of startup, the OxyChem teams who have been handling these chemicals for decades are preparing the subsystems and the process systems. And essentially, 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 really good day at site. Then we’ll start injecting water into one bay, and then mixing potassium hydroxide and the lime. And then we’ll start making pellets. Once we start making the pellets, we filter those pellets, we dry them, and then we start moving them through the mechanical handling systems to the cal signer. Start up the account signer and then start capturing CO2, which is a really big day at site. It’ll be very small volumes. As we do all of our projects, we’re looking for opportunities to reduce operating expense. We’re looking for opportunities to increase capacity. And so we wanna be really thoughtful over the next six months to try to learn as much as we can because the goal is really, you know, maximizing both of those outcomes over the next several years.

So, you know, just wanted to make that tie when you think about the rest of the year for us.

Roger Read: I appreciate that. It’d be exciting to watch. Thanks.

Neil Mehta: Our next question comes from Neil Mehta from Goldman Sachs. Please go ahead with your question. K. Yeah. Thanks for all the great information. Just a couple of midstream questions. Just love your perspective on the key drivers of that business looking at the guide here for twenty-five. One looks a little bit weaker, and then I guess it builds through the year as closer to breakeven. So just your perspective on the variables that are going into that and then I have a follow-up on this.

Sunil Mathew: Yeah, Neil. So if you look at guidance for 2025 compared to 2024, there are multiple moving pieces. So firstly, on the crude marketing side, you know, we’re gonna get a lower transportation cost. Like I mentioned in my prepared remarks, there are two transportation contracts that are expiring this year. Between those one is in Q1, the other one is in Q3. So this year, we’re gonna get a benefit of around $200 million. Next year, it’s gonna be $400 million. But some of that is partially offset by the annual FERC escalation of around three percent. So that’s on the crude marketing side. And on the gas marketing side, with the additional takeaway capacity now coming online from Permian, assuming lower differentials between Permian and Gulf Coast.

Then on the Alosin side, we are seeing higher sulfur price, which again should be an improvement compared to last year. And then on West, you know, we sold nineteen point five million units last year. So that is going to impact our income. So we’ll have lower distribution and lower income compared to last year. And the last thing on LCB, you know, which I just talked about, the startup and the ramp-up in Stratus, so which will also have a small negative impact on the income compared to last year. But what I would say is our midstream team is, you know, overall very well positioned to capture value when the market does present itself. And, again, last year, they demonstrated by beating the total guidance by around six million dollars.

Neil Mehta: Yeah. Really good numbers, Neil. Thank you. And that as a follow-up is just the framework around West monetization, recognizing there are a lot of moving pieces, but how are you thinking about the pluses and minuses of that as we think about deleveraging targets and how should we think about the tax component that goes into that equation as well?

Vicki Hollub: Well, to for us, we continually

Neil Mehta: look at opportunities and evaluate the opportunities, and

Vicki Hollub: it all comes down to the value proposition. And so you’re right that the tax impact would be a part of that value proposition when we’re looking at selling and investing in things that provide significant cash flow as West does. So that would have to be a part of what we consider. Our next question comes from

Doug Leggett: Doug Leggett from Wolfe Research. Please go ahead with your question. Hi. This is John Abbott on for Doug Leggett. Thank you for taking our questions.

John Abbott: Our first question is on the Gulf of America.

Doug Leggett: I mean, you spoke about 2025. Can you talk about visibility

Ken Dillon: beyond 2025 and how you see sustainable production?

Ken Dillon: Sure. It’s Ken here. I think we intend to, you know, have a goal of staying flat long-term. If you look at the projects that we’re working on at the moment, yes, we have the primary development drilling programs. We also have exploration. So this year, involved in two exploration wells. One basically underneath one of our facilities, which has two targets, myosin and the Wilcox target. And then the next wave is the EOR and Gulf of Mexico. Gulf of America 2.0. Project, which, you know, the water floods carried very low F and D, very low decline, very long-term. So again, each of these projects has accreted to lower costs long-term developments. And they’re not really pattern water floods. They’re basically pressure maintenance projects.

So it’s not huge drilling overheads on these existing facilities. We have unconventional opportunities. We have fracking opportunities. So the scale of the opportunity in Gong is, you know, hundreds of millions of barrels we see potentially there. And I’ve mapped out all of these Gulf of America 2.0 projects. We’re just working our way through them. So hopefully, that covers your question.

Vicki Hollub: I have to say that I share Ken’s enthusiasm about the Gulf of America. It’s really gonna be for us in the out years, three to five years, gonna be an important part of our growth story.

John Abbott: Appreciate it. And then the next question that we have was on your DUR business. You no longer break out your production in your

Doug Leggett: Financials?

John Abbott: Could you provide an update where production stands and

Doug Leggett: is still around a hundred and forty thousand barrels per day, which was your run rate a couple of years ago.

Sunil Mathew: Yeah. Thanks for the question for enhanced oil recovery. We remain excited about that business too as we look into the future. From a production level, it’s similar. We’ve had some slight decline over the last really, three years. I think you can see from our capital investment, it’s been a bit lower the last several years. But what that business has delivered is really great efficiency on cost. So when we talk about a lot of our operating expense reductions, they have led the way. They’re leveraged more to OPEX than they are capital, and so they can really help deliver good cash margin to our business or improving cash margin to our business with those improvements. In the future, you know, this is part of our strategy with, you know, CO2 and carbon capture.

And so as we get the ability to have lower-cost CO2, we’re excited about, you know, what that business can become very low, similar to what Ken talked about in the Gulf of America, very low F and D cost barrels at very low decline. And so when we bring that production on, it’s gonna provide nice cash flow attributes to complement the rest of our business.

Leo Mariani: And our next question comes from Leo Mariani from Roth. Please go ahead with your question. I wanted to ask just a general question around the low core ventures business here. Obviously, we’ve had a significant change in the administration, you know, here in the US, just wanted to kinda get a sense if y’all are thinking about that business, you know, differently over the next four years as you kind of proceed to prosecute things, sir?

Vicki Hollub: Not really. I mean, we are aware of the situation, and, certainly, there’s more uncertainty around CIRA and the infrastructure bill. But the way we view this is that CO2 is going to be much needed for the US. The reality is that for our extended energy independence, you know, the Shell revolution was an amazing thing that happened here in the United States. We believe the next round of technology that’s going to add significant barrels, fifty to seventy billion barrels of reserves will be production that comes from the use of CO2 in enhanced oil recovery. So forty-five Q is important for the development of the technology to get the CO2. There’s not enough organic CO2 in the country to be able to flood all the things that we’re gonna need to flood to get that fifty to seventy billion barrels.

And that fifty to seventy billion barrels would extend our energy independence by more than ten years. It’s critically important. And so taking CO2 out of the atmosphere is a technology that needs to work for the United States. And President Trump knows this, the business case for this. I’ve had several conversations with him. People around him understand the needs for at least some initial subsidies to help advance this technology just as you know, there hasn’t been really many transformational technologies that have been developed that didn’t have some sort of assistance at the beginning of it. And so we know that we have the capability to get the cost down on these direct air capture facilities. We’ve been so impressed with the combination of the Occidental Petroleum Corporation and carbon engineering team, the innovation that they’re developing so quickly is very, very helpful.

But to get to where we need to be, we really need to have forty-five Q. And so we’ve been talking with members of Congress and senators and we’ve met with many of the new cabinet members. We’re getting the story out that the next technology that must work and is very much needed is direct air capture to get the CO2 for these reservoirs. So we were optimistic that everyone we get around to everybody, we’ll understand the business case for this. But even if the business case is not completely what we expect, from the government, I do believe that we have the capability to get this down faster than we originally thought we would. And so that’s where we’re headed with it. It hasn’t changed our strategy in terms of what we’re doing with Stratos and the King Ranch DACH facility.

Operator: And ladies and gentlemen, in the interest of time, this will conclude today’s question and answer session. I would now like to turn the conference call back over to Vicki for any closing remarks.

Vicki Hollub: I’d just like to say thank you all for your questions and for joining our call. And hope you have a great rest of your day.

Operator: Thank you.

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