Occidental Petroleum Corporation (NYSE:OXY) Q4 2023 Earnings Call Transcript

Occidental Petroleum Corporation (NYSE:OXY) Q4 2023 Earnings Call Transcript February 15, 2024

Occidental Petroleum Corporation isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good afternoon. And welcome to Occidental’s Fourth Quarter 2023 Earnings Conference Call. All participants will be in listen only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Jordan Tanner, Vice President of Investor Relations. Please go ahead.

Jordan Tanner: Thank you, Gary. Good afternoon, everyone. And thank you for participating in Occidental’s fourth quarter 2023 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 Investor section of our website. The presentation includes a cautionary statement on slide two regarding forward-looking statements that will be made on the call this afternoon. We’ll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules for 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. 2023 was a great year for us, thanks to the performance of all of our teams in Oxy. I’m going to start by discussing our financial performance, operational excellence and our strategic advancements in 2023. Then I’ll review our capital plans for 2024. These continue to position us to deliver sustainable and growing returns for our shareholders through our premier asset portfolio, advanced technology and robust commercial runway. First, I’ll begin by reviewing our financial performance in 2023. Last year, our talented and committed teams across the company applied advanced technical expertise, operating skills, leading-edge technologies and innovation to our exceptional portfolio, and they delivered results, $5.5 billion in free cash flow, which enabled us to pay $600 million of common dividends, repurchase $1.8 billion of common shares and redeem $1.5 billion of preferred shares, while also investing $6.2 billion back into the business.

Next, I’ll comment on our operational excellence in 2023. Last year, our production in our global oil and gas business exceeded the midpoint of our original four-year production guidance by 43,000 BOE per day. This was driven by record new well productivity rates across our domestic assets in the Delaware, Midland and DJ basins, and internationally by record production from Block 9 in Oman. And in addition, we safely completed the expansion of the Al Hosn plant in the UAE, which also delivered record annual production. Despite negative price revisions, well performance across our portfolio enabled us to achieve an all-in reserves replacement ratio of 137% in 2023 and a three-year average ratio of 183%. Our track record from prior years of consistently replacing produced barrels continues and at an F&D cost that is below our current DD&A rate.

Oxy’s year-end 2023 worldwide proved reserves increased to 4.0 billion BOE from 3.8 billion BOE in 2022. OxyChem performed exceptionally well in 2023. It exceeded guidance and achieved $1.5 billion in pre-tax income for the third time in its history, due largely to lower energy costs and an efficient planned turnaround at our Ingleside plant, even as product markets softened compared to 2022. In addition, construction on STRATOS, our first Direct Air Capture facility, is progressing on schedule to be commercially operational in mid-2025. The fourth quarter of 2023 was an exciting way to conclude a successful year. In oil and gas, we delivered our highest quarterly production in over three years and outperformed the midpoint of our production guidance, despite a third-party interruption in the Gulf of Mexico.

Our Rockies business outperformed in the fourth quarter and that’s consistent with its year-long trends. Innovative artificial lift technology continued to maximize base production. Well-designed optimization in the DJ Basin that we presented in our second quarter earnings call contributed to a 32% productivity improvement from 2022. We also continued to deliver robust well performance in the Permian Basin, where our Delaware teams drove results to the high end of the Permian’s fourth quarter production guidance. Our Top Spot well, which we also discussed in our second quarter earnings call, continued its strong performance trajectory and delivered the highest six-month cumulative production of any horizontal well ever in the New Mexico, Delaware Basin.

In fact, Oxy has drilled eight of the top ten horizontal wells of all time across the entire Delaware, based on this production metric and three of those wells came online last year. Since mid-2022, our teams outperformed the Delaware Basin industry average 12-month cumulative oil production by nearly 50%. Our team aims to extend our leadership in the New Mexico, Delaware Basin this year. A significant portion of the 2024 Delaware program will develop the same horizon as the record Top Spot well. Further south in the Texas, Delaware Basin, our teams continue to deliver success with a couple of notable appraisal wells in the second Bone Spring and third Bone Spring line. These wells drove incredibly early time volumes and accordingly secured additional capital in our 2024 Delaware program.

Our appraisal programs are positioning us for success by adding horizons in the Delaware Basin and moving Tier 2 and Tier 3 wells to Tier 1. But we’re also improving our current Tier 1 intervals, for example, with our Top Spot well. Outside the Delaware Basin, we’re also making strides in some of the basins that we expect will begin to play a more consequential role. In the Midland Basin, technical excellence, including the basin-leading Barnett wells, drove a one-year cumulative improvement in well productivity of over 30% compared to the prior year. In the Powder River Basin, Oxy had one Wyoming state initial production and early cumulative production pad record of 1.5 million barrels of oil produced in only about seven months. As we highlighted, our uncommissional technical teams continue to expand and improve inventory across all U.S. Onshore basins.

While our subsurface modeling, innovative well designs and enhanced artificial lift technology have driven improvements in well recovery, new well designs have also resulted in record drilling times for both 2-mile and 3-mile Texas, Delaware Basin laterals. Similarly, in the Powder River Basin, our teams drilled an average 1,650 feet per day and we drilled a 10,000-foot well in only 11 days, both achieving Oxy basin records. Our successes are not limited to our Onshore U.S. portfolio. In the deepwater Gulf of Mexico, we are continuing to leverage technology to drive even stronger production results. Our subsea pumping system on the K2 field achieved first lift four months ahead of schedule. This is Oxy’s first deployment of this technology in deepwater.

We expect it to unlock future production enhancement opportunities and longer-distance subsea tiebacks. Next, I’ll shift to discussing how we advanced our strategy last year. In 2023, we high-graded our oil and gas portfolio, launched the expansion of our OxyChem Battleground facility and announced strategic commercial transactions that we expect will deliver sustainable multiyear value to our shareholders. These steps strengthened our portfolio and make it unique in our industry. We have high-quality, short-cycle, high-return oil and gas shale development in the U.S., along with conventional, lower-decline oil and gas development in Permian EOR, GoM, Oman, Algeria and Abu Dhabi. These developments are complemented by our strong and stable cash flow from our chemicals business and the cash flow and carbon reduction we expect our low-carbon ventures to provide in the future.

In addition to high-grading our oil and gas portfolio through organic development and appraisal work last year, we also announced the strategic acquisition of CrownRock, which will add high-margin, low-break-even inventory, while increasing free cash flow for delivered share. The incremental cash flow will support our cash flow priority of delivering a sustainable and growing dividend, along with deleveraging and share repurchases after reducing the principal debt to $15 billion. We are working constructively with the FTC in its review of the transaction and expect to receive regulatory approval and close in the second half of this year. The capital plan we will review in a moment excludes CrownRock, because we’ll continue to operate as two separate companies until we obtain regulatory approval and close the acquisition.

In our LCB business, we completed many pivotal transactions that provided technology advancement, third-party capital, revenue certainty and commercial optionality. We closed the acquisition of Direct Air Capture Technology Innovator Carbon Engineering last quarter. This was a landmark achievement in our Direct Air Capture development path. We’re excited also about our STRATOS joint venture with BlackRock, which we believe demonstrates the DAC is becoming an investable asset for world-class financial institutions. In addition, our team signed on several more flagship carbon dioxide removal credit customers. Now I’d like to reiterate our cash flow priorities and discuss our capital plans for 2024. On our December call, we discussed how we will focus on our cash flow and shareholder return priorities in 2024 on dividend growth, debt reduction and the capital allocation program that generates strong free cash flow throughout the commodity cycle.

As we discussed regarding CrownRock, we intend to complete at least $4.5 billion in debt repayments for both pro forma cash flow and proceeds from a divestiture program. We intend to prioritize debt reduction until we achieve a principal debt balance of $15 billion or below, including repaying debt as it matures. As a result of the acquisition, we expect to strengthen our balance sheet, improve our resilience in lower commodity price environments and free up cash from interest payments to support future sustainable dividend growth and shareholder purchases. Every year, we design our capital plans to support our strategic initiatives via projects that maximize our returns and best position Oxy to deliver long-term and resilient returns to our shareholders.

Our 2024 capital plan continues a bifurcated investment approach that balances short-cycle, high-margin investments with measured, longer-cycle cash flow growth investments. In 2024, we plan to invest $5.8 to $6 billion in our energy and chemicals businesses, resulting in slightly less capital for our unconventional assets this year. However, we expect our unconventional assets to return more cash to the business and we continue to expect year-over-year production growth and continued success across our premier unconventional portfolio, including some of the emerging horizons. We intend to complement our unconventional exposure with increases to our mid-cycle investments, including lower decline conventional reservoirs, which are expected to drive longer-cycle cash flow resiliency.

Our 2024 mid-cycle capital investments will position us to continue the exciting projects that we started last year. Investments in OxyChem are expected to increase this year as progress continues on the Battleground expansion and the plant enhancement project. We also added a second drillship in the Gulf of Mexico to support what we believe could become a future growth asset for Oxy. Lower decline oil production from our enhanced oil recovery or EOR, is an important part of our long-term strategy. This year, we’re investing in gas processing expansions for our Permian EOR business that support longer term growth in many of our core CO2 fields. Our EOR business will continue to be a key part of our future oil and gas development as we believe that carbon dioxide captured by Direct Air Capture facilities is a sustainable way to develop the 2 billion barrels of potentially recoverable oil remaining in our premier EOR operation.

In our emerging low-carbon businesses, much of Oxy’s planned $600 million 2024 investment will be directed to STRATOS. We have also allocated capital to continue preparations for a second Direct Air Capture and sequestration hub in South Texas, along with subsurface and well-permitting investments needed at our Gulf Coast sequestration hubs. Capital received from financial partners for our LCB businesses will add to our $600 million investment. This includes capital contributions from our joint venture partner, BlackRock, for STRATOS. BlackRock’s investment totaled $100 million in 2023 and we expect that figure will increase in 2024. We’re making great progress toward advancing our net-zero pathway as we develop Direct Air Capture and other exciting technologies.

We see tremendous potential in LCB to increase Oxy’s cash flow resilience and generate solid long-term returns for our shareholders. I’ll now turn the call over to Sunil for a review of our fourth quarter financial results and 2024 guidance.

Sunil Mathew: Thank you, Vicki. I will begin today by reviewing our fourth quarter results. We announced an adjusted profit of $0.74 per diluted share and a reported profit of $1.08 per diluted share, with a difference between adjusted and reported profit primarily driven by the after-tax fair value gain related to the acquisition of Carbon Engineering. Our teams exceeded the midpoint of guidance across all three business segments during the fourth quarter and we delivered outstanding operational performance. Higher-than-expected production in our domestic, onshore, and international assets enabled us to overcome production losses caused by an unplanned third-party outage in the eastern Gulf of Mexico. This outage led to a lower-than-expected company-wide oil cut and a higher-than-anticipated domestic operating costs per BOE.

It is also expected to impact production into early next month and is reflected in the guidance that I will soon cover. We had a positive working capital change, primarily due to receipt of the environmental remediation settlement, timing of semi-annual interest payments on debt and decreases in commodity prices. We exited the quarter with over $1.4 billion of unrestricted cash. Turning now to guidance. Last month, Oxy and CrownRock each received a request from the FTC for additional information related to the acquisition. The FTC’s request for additional information will impact the timing of closing, which we expect to occur in the second half of the year. Oxy will receive the benefit of CrownRock’s activity between the January 1, 2024 transaction effective date and close, subject to customer repurchase price adjustments.

Additionally, the issuance of senior unsecured notes, funding of the fully committed $4.7 billion term loans and termination of the existing bridge loan facility are expected to be aligned with the transaction’s closing. In 2024, we expect full year production to average 1.25 million BOE per day, representing low single-digit growth from 2023, with the Rockies and Al Hosn driving production growth. As Vicki mentioned, well-designed and operational expertise drove production outperformance in the Rockies last year. We anticipate that these results will continue in 2024, with a steadier run rate of wells coming online compared to the first quarter of last year when we recently ramped up brick activity. Permian production is expected to remain largely flat, with Permian unconventional capital decreasing by approximately 10% compared to the prior year.

Internationally, we anticipate continued higher production at Al Hosn following last year’s plant expansion. Total company production guidance in the first quarter reflects a low point for 2024, with a significant step-up expected in the remainder of the year. The expected first quarter decrease in production is primarily driven by the relatively lower activity levels and working interest in the Permian Basin in last year’s fourth quarter. January winter storm impacts of approximately 8,000 BOE per day in our domestic onshore assets, annual plant maintenance at Dolphin, and the Gulf of Mexico unplanned downtime event. Domestic operating costs on a BOE basis in 2024 are expected to decrease due to reduced maintenance in the Gulf of Mexico and improved lifting costs in the DJ Basin.

Moving on to chemicals. In 2023, OxyChem generated pre-tax income nearly matching its second highest year ever. This year, we are guiding to a midpoint of $1.1 billion of pre-tax income. This year’s full year guidance is close to the fourth best year ever for the chemicals segment, despite potential challenging market conditions. We expect that our first quarter OxyChem results will be largely flat from the prior quarter. Our guidance for Q1 reflects the combination of PVC price erosion largely associated with contract adjustments in Q4, typical seasonal subdued demand in both PVC and caustic, and export pricing pressure on caustic from China. Our guidance assumes that in Q1 we have reached the bottom of the cycle with more stabilized prices.

I would like to close today by looking beyond 2024 to highlight several catalysts that we expect will enhance our financial trajectory in the coming years. Our midstream business is well positioned to benefit from a reduction in crude oil transportation rates from the Permian to the Gulf Coast by the end of the third quarter of 2025. We expect annualized savings from these rate reductions of $300 million to $400 million, with approximately 40% of the savings starting in 2025 and the full annual savings anticipated in 2026. The OxyChem Battleground and plant enhancement projects are expected to generate incremental benefits to EBITDA of $300 million to $400 million per year once complete. In combination, these improvements to midstream and chemicals are expected to deliver an incremental annualized run rate EBITDA of $600 million to $800 million.

As Vicki discussed, we also expect the planned mid-cycle investments in our conventional Gulf of Mexico and Permian EOR assets to provide cash flow resiliency through lower decline conventional production. As we continue to execute on high-grading our premier portfolio, we are committed to meeting our deleveraging targets that I outlined in December. We believe that a strengthened balance sheet and Oxy’s premier portfolio will enable future increases to our common dividend and rebalance enterprise value in favor of our common shareholders. Our teams are focused on extending Oxy’s track record of operational excellence and solid execution on our path to delivering growing and sustainable shareholder returns over the long-term. I will now turn the call back over to Vicki.

Vicki Hollub: Thank you, Sunil. 2023 was a significant year for Oxy on both operational and commercial fronts. Our teams skillfully navigated through the dynamics and I want to recognize our employees’ ingenuity and hard work. Their efforts generated the exciting achievements we covered today, as well as the great progress that is underway to position us for a successful 2024. With that, we’d like to open the call for questions. Jordan mentioned earlier that Richard Jackson and Ken Dillon are also on the call and they will participate in the Q&A session. We’ll now take your calls.

Operator: [Operator Instructions] The first question is from Neil Mehta with Goldman Sachs. Please go ahead.

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Q&A Session

Neil Mehta: Thank you so much, and Vicki, great to hear from you. My question is just really around deleveraging and so you talked about this in the opening comments, but just talk about the path to getting balance sheet to where you want to be post the CrownRock acquisition, and how you see the asset sale market playing out here in enabling you to get that debt lower? Thank you.

Vicki Hollub: Well, as you notice, by virtue of all the M&A that’s happening, there’s a lot of appetite for companies to try to get into the Permian and we do have properties in the Permian that are not core to us but could be core to others and some of it just where they’re placed in the Permian geographically and how they’re not as cored up as some of our key areas. So the divestitures, I believe, will go well. What we won’t do, though, is we’ve decided not to make any divestitures until we close the CrownRock acquisition and then we’ll start a proactive process more aggressively at that point.

Neil Mehta: That’s great, Vicki. Thank you. And then on the Gulf of Mexico, the Q1 guide of 107 to 115, but the balance of the year 133 to 141, I’m guessing a lot of that’s around the pipeline outage. Can you just give us a sense of what are the gating factors to get that asset back online and how we should be thinking about the cadence of production over the course of the year?

Vicki Hollub: Yeah. We’re leaving the updates on that to the operator and so we’re not making any comments on that because we’re giving them room to get their business done. With respect to the rest of the year, we expect the rest of the year to continue on as normal and we expect that when we’re back up and running, we may get a little bit of flush production from that and we’ll have, hopefully, our target date for getting back up and online is pretty close to what we said. Do you have anything to add?

Ken Dillon: No. It’s Ken here. Maybe I can add a couple of things. So we’re feeling pretty good about the date, and for example, we’re sending our specialist startup crews offshore tomorrow to finish lining out the facilities for full operations. I think that gives you a feel for where we are in the process. The plants are in great shape. Our operations crews in parallel with the outage carried out our full 2024 turnarounds and also completed our enhancement projects for the year as well. So avoiding outages in 2024 gives us a really good shot. So we’re looking forward to it.

Neil Mehta: Thank you. Thanks, Ken.

Vicki Hollub: So — thank you. Appreciate it, Neil. That was time very well spent. They made use of all the time that they had to do things that we needed to do.

Operator: The next question is from Doug Leggate with Bank of America. Please go ahead.

Doug Leggate: Thanks. Good morning, everyone. I guess the number of course are shrinking, Ken. It’s great to hear you on the call after Conoco’s latest retirement. So thanks, Vicki, for getting on as well. So I have a couple of questions, if I may. I guess, the first one is, I hate to do it, but I want to come back on the disposal question. I realize you don’t want to give a lot of detail, but I want to frame it like this. When you bought Anadarko and you were trying to delever, I seem to recall you had about 25 different packages that were for sale, and of course, you ended up not having to do hardly any of those. I think it was about a dozen or something like that. So it seems to me that you’ve got a lot of things that you’ve already scrubbed.

So my question is, can you give us some color as to whether there is significant cash flow that would come along with the range of $4.5 billion to $6 billion? Without being specific on assets, what’s the associated free cash flow number?

Vicki Hollub: Well, depending on what actually is divested, we can’t really give you an estimate of what that is today. Some things are changing in terms of what we’re looking at. So I think that it would be very difficult to put the number out there at this point.

Doug Leggate: Is it significant? Would you consider it material, Vicki?

Vicki Hollub: Anything that’s material, we wouldn’t likely do. We’re trying to minimize the cash flows sold to ensure that we can maintain our cash flow. With that said, there will be some cash flow going, because it’s hard to sell any assets out here that we haven’t already at least done appraisal work on to generate some cash flow.

Doug Leggate: Okay. Thank you. My follow-up is on sustaining capital. You’ve stepped it up a little bit to $3.9 billion. But what we’re trying to figure out is this year’s growth is about 2%. You’re spending $6.5 billion, of which $1 billion is Battleground and DAC, which gets you to about $5.5 billion. So what I’m trying to figure out is, the growth rate of 2% seems to correlate with growth spending of about $1.5 billion. It seems — the ratio just seems a bit off. Can you help me understand how I should think about that?

Vicki Hollub: So if you look at our — what we’ve said we’ll spend in oil and gas is $4.8 billion to $5 billion in 2024, that — part of that will be spent on, as we mentioned, some of the mid-cycle projects that generate oil production at a later date. For example, the Permian EOR, investing in that would generate the oil and gas production from that in about the third year after we started. So that will be a bit delayed. Gulf of Mexico, some of those are also preparing us for the future. So the mid-cycle investments will not impact this year’s production. The potentially 2.2% increase will be based on the spending of the $4.9 billion, if you use the mid-cycle price, less than $4.8 billion. And then when you look at what’s being spent in our oil and gas operations minus that amount, you still have some of that going for our facilities.

I think it speaks well to what the teams have done with respect to productivity and getting more out of the wells that we can actually spend what’s really less than half that billion that you mentioned on oil and gas activities and then some of that will be for facilities. So we’re actually getting a 2% growth rate from some of what we’ve developed in 2023, going over to 2024 and then the high productivity that we’re getting out of our development.

Doug Leggate: That’s a great answer, Vicki. You’re still the most capital efficient portfolio by miles, so thank you so much for the answer.

Vicki Hollub: It’s really exciting what the teams have done and thank you for the question.

Operator: The next question is from John Royall with JPMorgan. Please go ahead.

John Royall: Hi. Good afternoon. Thanks for taking my question. So my first question is on midstream. I think one area that surprised us a bit was the full year midstream guide. You gave some good color in the slides, kind of bridging from 4Q to 1Q. But just thinking about bridging the full year, how would you characterize the moving pieces from full year 2023 to full year 2024? And then maybe what do you think the midstream business can do structurally kind of under mid-cycle conditions, excess $300 million to $400 million savings you’ve spoken about?

Sunil Mathew: Yeah. Hi. So one of the main drivers for the relatively lower guidance for this year is an assumption on the spread for the gas transportation contracts. So last year, we captured several gas transportation capacity optimization opportunities. For example, when the cold weather event occurred in the West Coast in the first quarter. So obviously we cannot predict these events, so our guidance assumes compressed gas transportation spreads. But when the market does present itself, we are well positioned to capture these opportunities. So that is one of the main factors. The other one is in Al Hosn. We’ve assumed a lower sulfur pricing for 2024 compared to last year. Now, sulfur prices are at a near-term low of around $70 per ton and that is primarily due to weak Asian fertilizer demand and also sale of built-up sulfur inventories by major regional producers.

But based on the market trends, we think — we see a potential improvement in prices during the second half from demand pickup and also unwinding of the sulfur inventory. And the last thing I would say is, we think this is sort of the low point in terms of the midstream income. We have assumed a narrow spread for the gas transportation for this year, and starting next year, we are also going to start getting the benefit of the two transportation contracts expiring, like I mentioned in my prepared remarks. So, looking forward, the next three years or four years, you should see a significant uplift in our midstream income.

John Royall: Great. Thanks for the color, Sunil. And then maybe just hoping for a little bit of detail on the $700 million BOE of additions to reserves. It’s a pretty big number, especially when considering you’re adding an acquisition this year. So maybe just some color on the sources of those additions and where they’re coming from.

Vicki Hollub: I think the bulk of the additions were from our Permian Resources business. I think the — I think just essentially most of it was. We had some revisions from productivity improvements in other areas, but the bulk was from Permian EOR, where I think, Richard, if you look at your reserve replacement ratio just for onshore, that was pretty significant.

Richard Jackson: Yeah. I mean, just to add to that, I mean, obviously the focus, while near-term, some of these highlights that we’re putting in on the primary benches that we’ve been developing, driving the outperformance on production. But some of the highlights we’ve been trying to put in the call are some of these secondary benches that are becoming more prevalent in our program. If you look at some of those highlights, so that second Bone Spring or the Bone Spring line, you look at that Delaware chart that we’ve got on cumu production highlighting the year-on-year performance in the Delaware, those secondary benches are outperforming our 2023 average. And so those — as we delineate and develop more of those, that’s really driving that reserves in the unconventional.

EOR continues to do well. Talk in more detail if there’s interest, but some of the projects they have going on there to increase capacity in some of our gas processing facilities, like in Seminole, which I think we highlighted, these are also giving us near-term, we call it operability or it’s really the reliability of that production. So some of that incremental investment this year is driving, say, a couple of thousand barrels a day of improved base production. But that’s also providing capacity to develop some of those low development cost barrels that Vicki noted as we’re able to bring on this CO2 for the future. So that’s sort of how we’re thinking about the reserve story and it plays out in near-term outperformance, but the long-term is picking it up on reserves as well.

Vicki Hollub: And I would add the other place where we did add significant reserves was Algeria. As a result of the team’s work to get all the 18 contracts merged into one and then extended. So that was great work done by the Algeria team to add reserves there. But the thing I’m most proud of is, while the bulk of the reserves came from those two sources, the Permian and Algeria, and a little bit from the DJ, every business unit we have increased reserves except for Al Hosn where we had already booked quite a bit of reserves because of the modeling work done there to get that estimate more refined.

John Royall: Thank you.

Vicki Hollub: Thank you.

Operator: The next question, excuse me, the next question is from David Deckelbaum with TD Cowen. Please go ahead.

David Deckelbaum: Good afternoon. Thanks for taking my questions today. I just wanted to follow up a little bit.

Vicki Hollub: Hi, David.

David Deckelbaum: Just — thanks. I wanted to follow up a little bit just on that prior conversation around EOR. I guess this is being built out in conjunction with some of the anticipated volumes coming from STRATOS. Can you give us a sense what sort of capacity in terms of production relative to where you’re at today? You’re intending to build out, or I guess, thought another way. How large do you anticipate the growth rate to be out of the EOR production base over the next five years to 10 years?

Vicki Hollub: I would say that over the next five years to 10 years, it’s going to be a significant part of our portfolio development. We have 2 billion barrels of resources remaining to be developed and we believe that as a result of our Direct Air Capture facilities that we ultimately will build to get CO2 out of the atmosphere, it’s going to be the most sustainable barrels in the world. It’s going to be a resource that the world needs to get to leave 30% or 40% of oil in conventional reservoirs, and 90% of oil in shell reservoirs. It’s just not acceptable. And for the United States to continue our energy independence, EOR is going to have to be a part of the equation. Ultimately, we’re getting way ahead of the game here to be sure that we’re ready, because we do believe that the climate transition would not be affordable for the world without EOR being able to produce net zero carbon barrels of oil.

So this is a huge part of our strategy and important not only to our shareholders who love value, but to the U.S., and ultimately, to other parts of the world. And for the nearer term, a forecast on what we can do, Richard has some data on that.

Richard Jackson: Yeah. Perfect. I’ll tie that. I mean, one of the attributes we really like around the EOR production that we talk about a lot is the lower decline. So as we came through the last several years, especially through the downturn with lower commodity prices, being able to have that flat — flatter decline, less than 5%, was able to help us maintain a lot of free cash flow. We really started restoration of some of that development last year, and this year as we go forward, we’ll have about 60 wells that we’ll bring online, which will add about 4,000 barrels a day of new well production. But the benefit of this EOR and we talk about mid-cycle, that doubles next year and triples in the third year. So you really hit your peak production of around 12,000 barrels a day based on that investment today three years from now.

The other thing I mentioned shortly, but just to provide a little more color, the Seminole gas plant expansion, that’s about 85 million a day that we’ll add in terms of capacity for about $40 million. Again, this year we’ll expect a couple of thousand barrels a day that we’ll add in our base production. So if you think about kind of a cash investment intensity or capital intensity, that’s as competitive as we’ve got in the portfolio. But what it does, to Vicki’s point, is we’re able to bring on our CO2, anthropogenic CO2 for the future. These are very good return projects. They’ll be very competitive in our portfolio, especially given the lower decline. So when we look at just that Seminole, as we look 2024 to 2028, that’s another 15,000 barrels a day to 20,000 barrels a day type opportunity for minimal capital.

So within sort of the range of capital that we’re spending this year in EOR, we’re building those sort of wedges with great opportunity to do more as we bring on more CO2. So hopefully that helps tie the short and the long.

David Deckelbaum: I appreciate the details, Richard. Maybe just sticking with the theme as a follow-up, just — I think you talked a little bit about some spending is in the budget this year for the second DAC facility, I guess, in Kleberg. Is any part of that sort of progression, excuse me, still contingent on conversations with the DoE and is – are you expecting a resolution around finality of funding and grants this year?

Vicki Hollub: The discussions with the DoE are continuing and going quite well. That — where we — the timing of the start of the front-end engineering and design will be dependent on the completion of some of those discussions and then the discussions will continue beyond that on getting prepared for the start of construction. But there is a timeline there that we’re working through.

Richard Jackson: Maybe just a couple of details I’ll add since you asked the question on that. I mean, a lot of that spend is continuing to build out the subsurface capability for that CO2. Obviously, Direct Air Capture is an anchor for the King Ranch area, but we continue to work on our other Gulf Coast tubs. We’ve submitted eight Class VI and are expected to submit another 10 this year. So just kind of giving you a scale of what that type of work has been going there. So it’s going really well. I’m really pleased with the development work on that end, and then, obviously, Carbon Engineering, we’ve been getting to work more and more with, and I’m really happy with the progress that is going through R&D to project work with Ken that will fulfill that development work.

David Deckelbaum: Thank you both.

Operator: The next question is from Roger Read with Wells Fargo Securities. Please go ahead.

Roger Read: Yeah. Thanks. Good afternoon. I guess I’d like to come back to two things, please, Vicki. First one on the CrownRock, if there’s anything you can kind of offer us on what the FTC is asking you for a second request. And I’ll just sort of preface with, I understand with some of the more integrated companies, the concern of concentration. I’m a little more surprised in a more upstream-oriented company. So anything you can help us with there?

Vicki Hollub: Well, some of our teams felt like they’d asked for everything. But I can tell you our teams are working diligently to work with the team at the FTC to get them all the answers that they need. So it’s — we’re progressing and hope to, as we said, be able to close in the second half of this year.

Roger Read: So they asked for the moon and everything else?

Vicki Hollub: I didn’t — well, I didn’t see the moon on there, but we’re not done yet.

Roger Read: Fair enough. All right. The other question I had in terms of the capital efficiencies are obviously coming through in the Permian. The regular, let’s call it, still modest growth there. But you’re increasing the growth rate during 2024 for the Rockies and other part of it. When we had the follow-up calls yesterday, they said part of it was, building some mid-cycle businesses, maybe some somewhat lower declined businesses. I was just wondering, from a corporate structure, how you make the decision on where to allocate the growth capital here, like, why lean more into the Rockies and the EOR rather than the Permian when we’re kind of all conditioned to thinking of the Permian as among the best returns in the business, and obviously, the performance you’ve been delivering at the wellhead kind of says, well, why not more capital in the Permian rather than these other opportunities?

Vicki Hollub: Well, when you look at it on a corporate level, what we’re really trying to do is balance our investments over time so that we can have a sustainable growing dividend. And it’s — we’ve got this unique balance that I think makes it for us different than many other companies and we want to take full advantage of it. And I want to let Richard and Sunil chime in on their views on it, because this is a critical part of what differentiates us.

Richard Jackson: Yeah. No. Roger, appreciate the opportunity. I mean, obviously, we’re putting together short-term with long-term in mind and the CrownRock acquisition provides a lot of growth and we’ve talked about the positive attributes of that being a more mature unconventional development with high margin, 35% decline. It immediately adds, you can think about it from a growth standpoint, a really nice growth wedge this year, both from a free cash flow basis, but also a decline basis. The Rockies, I’ll just pick on one point there, about 40% of that capital in the Rockies this year has to do with drilled uncompleted wells that carried in from last year, sort of the cadence of that activity levels, we had resumed activity last year, got ahead on the drilling and then this year really beginning to complete a lot of those wells.

So from a capital intensity standpoint, that’s very, very low when you look at what we’re spending for the amount of production that we’re able to add there. Obviously, that’s — we have high margins in the Rockies. We have royalties. There’s other things that drive very competitive returns there. And so, that duck count, just as a data point, will kind of go from, say, mid-60s, kind of the fourth quarter of last year to more like mid-30s as we balance and that’s allowing us to then actually pull back about a half of a net rig in the Rockies to more of a sustainable activity level. So just a little color on the Rockies so we don’t read too much into just one year. But maybe Sunil can then pick that up and talk kind of across the company.

Sunil Mathew: Yeah. So when we think about capital allocation in the oil and gas segment, what we’re trying to do is we’re trying to balance between margin, base decline and capital flexibility. So if you start with cash margin, we start with the U.S. unconventional with high margin, high returns and based on everything we’ve heard so far, it’s getting better each year. And then you have Gulf of Mexico, which has one of the highest cash margin in our portfolio. And if you look on an incremental basis, it’s even higher because a large part of the operating cost is fixed. And then you have international assets, which are mostly production sharing encompass [ph], where we get a higher share of production at lower prices and this helps mitigate some of the commodity price risk and protect the overall cash margin.

So that is from a margin point of view. And when you think about base decline, so today our production, approximately 60% of our production is unconventional and with CrownRock it’s going to get to around 65%. So what we are trying to do is balance between the short-cycle, high-end decline and conventional, and then the mid-cycle, shallower decline, conventional investments. And Permian EOR, like Richard said, has one of the lowest base decline in our portfolio. So, if you look at a typical Permian EOR project, we get to the peak production by the third year and the peak production is almost 3 times the first year production and then after that, it is a shallow decline. So, what this does is, it helps manage our overall corporate decline, which helps with the sustaining capital and which ultimately helps with the break-even.

And the third part of it is capital flexibility. So, if you look at our CapEx, even for this year, around 75% of upstream CapEx is U.S. Onshore, where we have flexibility to change activity depending on the macro conditions. So, like if you look back in 2020, in U.S. Onshore, we had around 30% of the rigs that we planned to operate this year. So, we were able to wrap up quickly and efficiently and we can do this if the macro demands that. So these are the three attributes that we look at when we look at oil and gas capital allocation. So to summarize, what I would say is we have a diverse portfolio of both conventional and unconventional assets that helps manage our base decline, while also maximizing our returns and also providing the flexibility to respond to different macro conditions.

Roger Read: That was very thorough. Thank you.

Operator: The next question is from Neal Dingmann with Truist Securities. Please go ahead.

Neal Dingmann: Thanks for your time, Vicki and team. My first question, Vicki, is on the DJ. I’m just wondering, could you remind me where you all sit, I think, in good shape? I’m just wondering where you all sit on total permit pertaining to your DJ D&C [ph] plan, and then while early, are you all concerned about the, I saw some latest potential proposed Colorado Bills?

Vicki Hollub: Yeah. I’ll pass that to Richard.

Richard Jackson: Yeah. I think just from a permit standpoint. It’s been very productive over the last couple of years. So we stand today about a little over a rig year or 1.5 times kind of our current activity. But in the last six months, we’ve gotten 155 through. In the next 12 months, we expect another 169. So there’s some big ones that we’ve been working through kind of from a larger package standpoint that have gone really well. That team there, and I hope this helps kind of second part of your question, we continue to drop things that are important to the communities and the state around emissions. Our safety programs are very good. We’ve worked on consolidating facilities and doing things around transportation to make it easier and so a lot of those things have been really the positive things we’ve been able to add into these permit or development plans around the permits that we’ve received very positive comments on.

So we’re continuing on. Again, we’re sort of hitting more stable, sustainable activity up there and we feel like we’re as good a position as we have been in a long time in terms of permit outflow.

Neal Dingmann: Very helpful, Richard. And then just a follow-up on charitable return and M&A. I’m just wondering, I assume now that the preferred redemptions would now not incur until late 2025. So is it fair to assume that when you were looking at the CrownRock acquisition that you factored in that any CrownRock incremental production or free cash flow would more than offset any mitigated payments now for another year or so?

Vicki Hollub: Yes. That’s what we figured on that. But the CrownRock does that acquisition. Once we get our debt back down to $15 billion, that’s going to be a key part of helping us then to start the resumption of a more robust share of purchase program of both the common and ultimately the preferred.

Neal Dingmann: Great point. Thanks, Vicki.

Vicki Hollub: Thank you.

Operator: The next question is from Josh Silverstein with UBS. Please go ahead.

Josh Silverstein: Yeah. Thanks. Good morning. I was going to ask on kind of similar topic there. Now that the asset sales are pushed out and you don’t have the term loan coming in just yet, is the shareholder return profile just the base dividends this year and that kind of supports you getting to that $15 billion debt number a bit faster?

Vicki Hollub: No. Actually, we would — we’re going to accumulate cash flow as we continue to work toward closing the CrownRock deal, because a part of cash flow will be used to help pay down both the term loan and our debt maturities that are coming. So cash flow would not be used for share repurchases until we get to the point where we’ve achieved those goals.

Josh Silverstein: Got it. And then I saw that the Battleground project was pushed out to 2026. If you could just go through any sort of the drivers of the extra time that was needed and what the status of the other plant enhancement projects look like and maybe what the spread of that $350 million EBITDA uplift was, like, kind of between Battleground and the other projects? Thanks.

Vicki Hollub: I think, there is — the projects there were pushed out a bit just like many other things because of supply chain issues and also dealing a little bit with inflation. But those projects, we started those and those are in progress and going well at this point. So I’d like to say that, though, the importance of when those cash flows come on from the plant enhancement projects, we’re already starting to see cash flow from those projects. The actual cash flow that we’ll see from the Battleground expansion won’t be until the second half of 2026. But the exciting thing about all of this is that, when you add the OxyChem projects, which will deliver the $300 billion to $400 billion, the full uplift by the second half of 2026, that’s both the plant enhancement projects and the expansion.

So we’ve got that and you combine that with what Sunil had talked about earlier where we have a $400 million reduction in our mid-cycle contract prices in 2025. We’ll see the full uplift of that in 2026 as well. And so when you combine those along with the $1 point — $1 billion that we expect, assuming a WTI price of $70, that puts us in 2026 with $1.7 billion incremental cash at least and potentially more than that. So to be able to get to a point where, in just a little over two years, where we have through these projects and cost reduction, we are $1.7 billion better in terms of cash flow, that’s pretty significant for us and something that we’re really looking forward to and excited about.

Josh Silverstein: Great. Thanks, Vicki.

Operator: The next question is from Michael Scialla with Stephens. Please go ahead.

Michael Scialla: Yeah. Hello. I appreciate all the detail you gave on the decision to direct more capital this year to mid-cycle investments. I wanted to ask specifically about the Gulf of Mexico, which is part of that. Back in December, you were planning on just the two drillships. So I wanted to see what change you’re thinking there to add a third drillship and especially given that services there seem to be tighter than they are onshore. Was it just part of this whole mid-cycle investment thesis or is there something else? Can you talk about specifically what you’re seeing there that that third drillship will be targeting?

Ken Dillon: In terms of drillships, we’re only planning on two drillships this year. In terms of GoM overall and how it plays into the portfolio, last time I mentioned our GoM 2.0 project. Based on that, we’re carrying out detailed reservoir characterization work and can see significant upside potential in the GoM assets. I mentioned water floods, stimulation, horizontals, artificial lift and subsea pumping, which is already operational for us. If I talk a little bit about water injection, when you already operate fields with original oil in place numbers of billions of barrels, adding water injection is a really economical way of increasing recovery factors on high margin, low development cost barrels. Typical improvements in recovery and appropriate reservoirs can be between 10% and 16%, while also significantly reducing declines, so it plays into the things that Richard was talking about in EOR.

The scale of these developments and the very low development costs lead to good returns. Analogs have been highly successful in GoM. As you know, we’re world leaders in these technologies. We do them in every country that we operate in, and domestic is the foundation of who we are. I’d also like to highlight the OBN seismic activity that we’ve done since 2020. That’s really helped define these targets, the scale of them and it’s assisting in the well planning and well locations that we’re working on at the moment. I think we see GoM as a portfolio now, with great optionality to grow using the existing infrastructure that we have in place, but also the technology skills that we have across the entire company. I hope that answers your question.

Michael Scialla: Yeah. It does. Appreciate that, Ken. I know on your CrownRock acquisition call, you mentioned, I think Richard mentioned EOR pilot. You’ve been working on the Midland Basin for a couple of years. I just wonder if there’s any plans to expand EOR in the Midland in the near-term and did that have any bearing on your decision with the CrownRock acquisition?

Vicki Hollub: The CrownRock acquisition stood on its own in terms of quality and how it fit within our portfolio in the Midland Basin and it made that asset stronger. But the four pilots that we conducted in the Midland Basin were on the South Curtis Ranch, which is not too far from some of those assets. So we do believe that the Midland Basin is going to be one of the areas that we would target in a big way with an enhanced oil recovery development that’s using anthropogenic or atmospheric. But we’re also doing the same thing in the Delaware Basin now. We have a pilot going on there that will help us to potentially look at that as another place to develop ultimately. So we have both options.

Michael Scialla: Very good. Thank you.

Vicki Hollub: Thank you.

Operator: In the — excuse me, in the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.

Vicki Hollub: I’d just like to say thank you all for participating in our call today. Have a good day.

Operator: The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.