Good afternoon and welcome to Occidental's First Quarter 2024 Earnings Conference Call. [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.

Thank you, Drew. Good afternoon, everyone and thank you for participating in Occidental's First Quarter 2024 Earnings Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Sunil Mathew, Senior Vice President and Chief Financial Officer; Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management and Ken Dillon, Senior Vice President and President, International Oil and Gas Operations. This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. We'll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules to our earnings release and on our website. I'll now turn the call over to Vicki.

Thank you, Jordan and good afternoon, everyone. I'm pleased to report on a strong start to 2024, driven by our persistent focus on operational execution. As we will detail in today's call, our oil and gas business delivered robust production results essentially offsetting an extended third-party outage, while our Midstream and OxyChem businesses outperformed our first quarter guidance. Today, I'll start by discussing our first quarter performance, including highlighting our Delaware appraisal success and its contribution to Permian's development runway. Then I'll discuss what's on the horizon for Oxy and how these initiatives are expected to generate significant value for our shareholders. Operational excellence is fundamental to everything we do at Oxy and our capabilities were evident during the first quarter as our teams generated over $2.4 billion in operating cash flow before working capital. Though the third-party outage in the Eastern Gulf of Mexico made it a challenging start to the year, our teams delivered excellent performance in all areas of our portfolio. We concluded the first quarter by approximating the midpoint of our production guidance and we restarted production from our Gulf of Mexico platforms affected by the outage in mid-April. Taking a closer look at our production results, the first quarter benefited from strong new well performance in the Permian Basin and the Rockies, overcoming the impact of winter weather early in the year. In the Permian, we exceeded the midpoint of our production guidance due in part to better-than-expected secondary bench performance in the Delaware Basin. Our Delaware teams are achieving impressive performance by results -- performance results by applying the same proprietary subsurface workflows that have generated remarkable success in our primary benches and applying that to secondary benches. Through utilization of fit-for-purpose well design and reservoir characterization expertise, performance in our secondary benches is…

Thank you, Vicki. In the first quarter of 2024, we generated an adjusted profit of $0.63 per diluted share and a reported profit of $0.75 per diluted share. The difference between adjusted and reported profit was primarily driven by our litigation settlement gain related to the Andes arbitration and gains on sales included in equity income, partially offset by derivative losses. We exited the first quarter with nearly $1.3 billion of unrestricted cash. We had a negative working capital change, which is typical for the first quarter and is largely due to semiannual interest payments on our debt, annual property tax payments and payments under our compensation plans. During the first quarter, we delivered over $700 million of free cash flow before working capital despite third-party outage impacts to portions of our oily high-margin production in the Gulf of Mexico. First quarter free cash flow was underpinned by outperformance in our onshore domestic portfolio and our Midstream and OxyChem segments. Looking ahead to the second quarter, total company production is expected to increase to a range of 1.23 million to 1.27 million BOE per day compared to the first quarter annual low of 1.17 million BOE per day. The midpoint of second quarter production guidance will be the highest quarterly production in over 3 years. The production increase is mainly due to U.S. onshore activity levels, the completion of annual plant maintenance at Dolphin and the return of production in mid-April from the Gulf of Mexico outage. Our second quarter Gulf of Mexico production guidance includes third-party outage impacts in April as well as plant maintenance in the Central Gulf of Mexico. Though we revised full year Gulf of Mexico production guidance down, as a result of the extended outage, it is fully offset by outperformance in the Rockies and…

Thank you, Sunil. Before we move to Q&A, I want to tell you about a milestone our team celebrated last quarter. Oxy began trading on the New York Stock Exchange on March 3, 1964. On that day, our operations consisted of 252 oil and gas wells in 6 states. Today, we're an international energy, chemicals and carbon management company with the best portfolio in our history. But I believe that Oxy's employees are a true differentiator. Their expertise and drive to outperform continue to stretch the limits of what is achievable in our industry. Our employees are hard at work executing our strategy through superior operations and best-in-class assets. Their efforts result in long-term shareholder value and I look forward to showcasing more of their achievements on future calls. With that, we'll now open the call for questions. And as a reminder, as Jordan mentioned, Richard Jackson and Ken Dillon are with us today for the Q&A session.

[Operator Instructions] The first question comes from Roger Read with Wells Fargo.

Yes. Thank you and good afternoon. I'd like to -- if we could maybe just dig in a little bit more on the Permian outlook here, probably including the Rockies, maybe let's just call it the Lower 48. If we look at the CapEx and then we look at the forecast for the full year, I'm just a little curious why you didn't get a little more optimistic about total volumes? And I recognize that within the year-over-year changes, we're looking at a little more EOR, maybe a little less shale wells. And I was wondering if that's part of the difference we're seeing or maybe why we don't see production raised as well?

Richard?

Yes. Thanks, Roger. Appreciate the question. I mean clearly, very pleased with our first quarter results coming out of the -- both the Rockies and the Permian. Both had [indiscernible] on the quarter, with Permian looking good on several fronts. I'll focus there first. I guess, a couple of things just to kind of anchor the year on. As we think about going from first quarter to the second quarter, which Sunil mentioned, quite a big step up in terms of production but even looking at first half versus second half in the Permian, the implied increase is about 18,000 barrels a day first half to second half and we're doing that while reducing rigs for -- in the Permian. So we're getting more with less in terms of how we think about activity. Some of that plays through on the capital, as you mentioned, as we're a bit front-load heavy, both on rigs but also facilities as we're front-loading the facilities in the first half of the year to take on that production increase starting next quarter. The good news is, things are performing well. And so when you look at the year and you think about the trajectory we're going on with things that are meaningful to our business, we highlight the new well production, not only the primary zones, which we've highlighted over the last couple of years but now, especially this quarter, we really wanted to highlight the success of the secondary benches that play a meaningful role in our portfolio for the year. The other thing that we don't talk enough about is base decline. And so if you look at our Permian resources this year, we're improving. Our base declined from last year about 4% to 5%. That's around 15,000 barrels a day. And…

Okay, appreciate that. I guess the other question I had just -- you talked about it on the intro there, Vicki but the performance of the midstream, how much of that is something that we ought to think about as we're going to go forward over the next 1.5 years, 2 years? We'll have another period where we're probably constrained on being able to move oil and gas out of the basin just maybe a way to think about other opportunities coming forward for you all to capture a little bit better?

Well, for us, it's not really -- we don't have an issue moving oil or gas out of the Permian Basin. And in fact, some of the things, the positive impacts for our midstream performance are due to the fact that, from a gas perspective, we have capacity elsewhere so that we can move molecules around too and trade molecules. And we have ways to get gas to California and to other markets. So from a gas marketing perspective, we're in really good shape and take away capacity in good shape there. Oil, we're also in good shape. We have overcapacity now to get barrels out of the Permian. So when we talk about fluctuations in the Midstream business with respect to crude marketing, normally that -- some of that's associated with picking up the third-party barrels that are associated with the capacity that we need to fill with incremental barrels above and beyond our current production. So that's the volatility mostly in the Midstream business, that, along with the gas marketing, does cause volatility. But normally, that volatility is [indiscernible] the upside for us because of the fact that, as I just mentioned, we have the capability to move things around and to take advantage of situations that -- where others are disadvantaged. So while with Waha and the situation that it's in now, our upstream realizations are lower but our Midstream business is able to capture opportunity to offset that.

The next question comes from Paul Cheng with Scotiabank.

Vicki, or maybe, this is for Rich, in there you were -- you're talking about the secondary branches, I think there's the Bone Spring. Is it -- why spread too far your entire operation or specifically in certain countries? Is there any kind of characteristic that you can see in terms of the pattern that will lead to this very strong performance wells from those branches for that -- those area? So we're trying to understand that, I mean how important it is to your overall operation or your overall inventory level? And secondly, that your DJ has been performing really well, has been, I think, beating your own guidance for a number of quarters actually, I mean, at least for, say, 7 or 8 quarters already. So from that standpoint, is your current estimate maybe a little bit conservative that for the remaining of the year in the DJ? And also that, I mean, what are the primary reasons for the outperformance there?

Yes. Thanks, Paul. I'll start in the Permian and get to the Rockies. I think what -- the way we describe sort of our approach to primary benches and then it's turned into our secondary benches is really unique by area. And so we spend a lot of time and we've talked about it in the past, really focused on the subsurface aspects, both from a geologic perspective and then as you think about it over time, from a reservoir perspective. And so I think as we've continued to delineate and be more broad in terms of the zones that we put together in areas, we focus on how do we put these wells in space together in the subsurface to optimize that recovery. And, of course, your stimulation design and these other factors play an important role. So I don't think it's unique by area. I think it's the same approach that we've delivered in terms of the Midland Basin with the success we've had in the Barnett, what we're doing in the Delaware Basin, whether it's upper Bone Springs or deeper Wolfcamp. And I think, as we think about the Rockies, the same sort of approach there. In terms of the Rockies, they've had great performance over the last really year plus. And a lot of that started with the subsurface approach where we really spent time thinking about how do we approach lateral length spacing, stimulation intensity and I think a lot of the early gains we were seeing there. I think what we're seeing today is a lot more operational. We talk about how do we draw these wells down. So early time flow back and then longer term. And what we're seeing is really improvements in both. So in the early time performance, it's really having the facilities and the emissions handling to do that, not only at a correct rate but to handle the emissions. And then long term, we've talked about the base recovery with things like our plunger lift assist, kind of AI. And so these types of things are really what delivered the overperformance. I wish I could say it was conservative. I just think they've improved so much. When you're improving better than 20% year-on-year, that's sometimes tough to outlook. But I think they've gotten more mature in terms of some of these advancements over the last year and I think we've done a lot better job sort of narrowing the uncertainty of those outlooks. But all the teams are still on the hook to outperform this year. We're optimistic, like I answered earlier, in terms of what we're doing in the Permian as well. So I appreciate the question and hopefully, that helps.

The next question comes from Neil Mehta with Goldman Sachs.

My first question is just around noncore asset sales, recognizing we still have some time before the deal closes. But I would imagine you continue to have conversations around the divestments. And so just curious what your perspective is on the market right now and your confidence in the achievability of up to the $6 billion of noncore asset sales that many have anchored to?

Yes. It's -- there's a lot of incoming interest. Once we announced that we were going to divest between $4.5 billion and $6 billion, Sunil started getting a lot of phone calls and letters. And so the interest is there and it's very high interest. And what we're hoping and expecting is that, that high level of interest translates into appropriate levels of offers for the things that we might consider selling. But it all comes down to valuation and that's going to make the difference for us because we do have options and as you know, lots of acreage. So we're going to make the best value decision that we can. But we don't see that there would be any impediments barring something that we haven't foreseen that would cause us to have issues with our divestitures.

And the follow-up is just your perspective on -- sorry, please Sunil.

Yes. What we were going to do is just for those that haven't heard, Sunil is going to go through the kind of what we think about with respect to divestitures, just to give those who might be listening get an idea of what we're looking at.

Yes. So as we have said previously, we are evaluating our portfolio, the high-graded portfolio and identifying what are the assets that does not fit in our development plan -- in our near-term development plan and -- but that could be attractive to other companies. So what is the strategic fit of that asset in this high-graded portfolio? And like Vicki mentioned, what is the value that we can get? And can we potentially accelerate the value by monetizing this asset? So like Vicki said, we're getting a lot of inbounds even before the announcement and a lot more after the announcement but this is the criteria that we're using to evaluate, is this an asset that we want to potentially monetize? And going back to your question about $4.5 billion to $6 billion, yes, we are fully committed to achieving the target within 18 months of closing. And between the proceeds from asset sales and organic cash flow we want to get to the $15 billion of principal debt that we have outlined.

That's great perspective. And then the follow-up is just on Battleground. I'd just love your perspective on both the chlorine and caustic soda markets. And how do you think about the outlook there? And once the expansion comes online, do you think that changes the supply-demand dynamics for any of these products?

Just to go back and look at what OxyChem has been able to do in the last few years. When we think about pricing of PVC and caustic soda this year, we've just come out of an incredible super cycle where, in 2022, we achieved our highest annual earnings ever, our second best earnings in 2021 and our third best in 2023. Now that we're into 2024, prices don't seem to be quite at the bottom. And as we were going through the first quarter, we started to see some strengthening and -- of caustic soda and PVC a little bit. But the reality is that inflation in the United States, along with very weak demand out of China because they're basically overbuilt right now in both commercial and residential housing and buildings, so we don't see China demand getting better anytime soon. But we do believe that beyond this year, getting past our inflationary environment that there was -- there's some certainty around some reduction in inflation. We think the housing market is already primed for growth again. And so if we could get to an inflation level that is conducive for that, we'll certainly see -- start seeing recovery in prices here in the United States. The international market and we do export, so the international market impacts us. And so we'll continue to see some pricing challenges in that market. But ultimately, getting beyond this year and the next 18 months, I do believe that driven by India and other places that we'll see growth in demand again and that we'll start seeing prices going back up. So we're feeling like we're probably at a bottom right now.

The next question comes from John Royall with JPMorgan.

So just thinking about the $400 million from midstream contract roll-offs. How much of the better terms baked into those numbers are you modeling that's locked in today versus what you're just kind of expecting? And to the extent [indiscernible], what's your level of confidence in terms of going the other way as we get closer to the roll-offs?

I'm sorry, could you repeat that question a little bit. We had some disturbance.

Mr. Royall, could you pick up, if you're on a speaker phone, pick up the handset by any chance?

Is this better? Can you hear me now?

I think that is better. Go ahead Sir, please repeat your question.

Okay, apologies for that, Vicki. So just thinking about the $400 million from midstream contract roll-offs. How much of the better terms baked into those numbers if locked in today versus kind of what you're expecting? And what's your level of confidence that, to the extent if not locked in, that it might not go the other way before you have to renegotiate?

I have high confidence that we'll achieve the $400 million and some of that we're already seeing today. And I do believe that we wouldn't, trust me, we wouldn't say it if we weren't pretty confident that we'll get it.

And John, it's this confidence that actually helped us increase our cash flow -- incremental cash flow from $350 million to $400 million.

Yes.

Fair enough. And then apologies if I missed anything on this but I was hoping you could get into the 2Q OpEx guide a little bit, which is somewhat flattish with 1Q despite higher production with the GoM back up. So it looks like a numerator issue and not a denominator issue. Just maybe any color there on the OpEx guide.

I think the OpEx guide was driven mostly by the impact of the Gulf of Mexico production and the production coming back on. It's -- I don't see any differential there. Do you?

No, I think that's right. That's -- yes, we're seeing improvement with Gulf of Mexico production coming back. But again, like I mentioned in my prepared remarks, the second quarter does include some impact from the pipeline outage and we also have a planned shutdown in Central Gulf of Mexico. So by the time you get to the third and fourth quarter, you should see an improvement in the operating cost.

Yes, John, just to add to that trajectory. Q1 actuals were at $10.31 for U.S. LOE and we're outlooking $10.10 in the second quarter.

The next question comes from Neal Dingmann with Truist.

I think my question is on the -- your Permian D&C plans, particularly around Slide 24, I like what you're showing there. You all suggest, I guess, running about 21 rigs this year on average. This is kind of something you talked about after running -- I think it shows what -- is it 24 in the first quarter? And I'm just wondering trying to get a sense of the cadence, would it just be a sort of typical ramp down. And I'm also wondering if your operational efficiencies continue to be as good as they've been, would you let some rigs go and continue kind of with that production plan? Or would you maybe just ultimately end up producing more?

Yes. Perfect. Yes, I appreciate the question. Like I mentioned earlier, the plan is to ramp down just sequentially kind of as we go into the second half of the year. And really, that's been the plan since we boarded and came out. So we are seeing good operational efficiencies. I'd say time to market really in every area is slightly improved. So we'll consider that as we go into the year to just kind of understand how that may accelerate any capital and how we want to respond to that. I would say 1 thing that has played out well, we noted these cost improvements and a couple of things to note. Beyond just operational efficiencies, we are seeing some good outcomes as we work with our service providers like [indiscernible]. And so we've been able to, kind of as we relook and hit that more level wise, let's say, balance and activity in the second half of the year, our utilization is going up about 10% on our frac core. So that's more pumping hours per year and that's both good for us but also good for our frac providers in terms of how they manage their business. And so those types of things are delivering these savings which we think will pace well even with some acceleration in our operational efficiencies. So as the cadence goes this year, we're heavy on D&C to start the year and facilities as well, like I mentioned. And really in that back half of the year, you'll see that capital drop and you'll see the production increase. And so looking forward to that. And then that should set us up at a much more level loaded and optimized pace going into 2025. And so obviously, we'll have options depending on where Vicki wants to take us with our capital program but that's sort of the thinking going into this year and into next.

That's what I was looking for, Richard. And then Richard, quick follow-up on the Permian for my second. How do you view the typical these days, you're doing great on bulk but your typical Delaware versus Midland well economics? Why I ask is, just looking at the curves you all show on Slides 25 and 29, which is again, I think [indiscernible]. I think you're showing around 450,000 BOE in the Del after a year versus around 250,000 BOE in the Midland, which again, knowing that they're cheaper wells, just wondering maybe in broad strokes, how you think about the difference in the economics?

Yes. I mean, you're saying it right. I mean, I think -- and it's the same way we think about these primary and secondary benches, even in the Delaware, the cost matters. And it's not only the drilling and completion costs, you can look at a little bit shallower, a little bit different drilling in the Midland Basin leading to lower drilling and completion costs. Same for the secondary benches in the Delaware to get a little shallower into the Bone Springs, they're cheaper. And so it's certainly, you see it play through on the D&C. But the way the team's put together their development areas, they think about the impacts on facility costs. So one of the examples, I know we had reviewed here recently, we had some shallower Bone Spring wells that came on, I think, about 3 years after we drilled the Wolfcamp wells. And the returns for those secondary wells, even with lower production, was about double the primary. And that was because we were able to reutilize these production facilities. And so that timing of how you put that production together can make a tremendous impact on the improvement of the economics. And so as you think about it in basins, we do the same thing. The advantages of being more balanced in the Midland Basin allows us to optimize all these facility costs, maintenance costs, all these things to make sure we're getting the most production per dollar spent, not just capital but even OpEx. So appreciate the question and that's absolutely how we look at balancing the capital, looking for that full cycle return forward.

The next question comes from Scott Gruber with Citigroup.

Staying on the topic of the Permian. Can you provide some color on what's included in the Permian unconventional inventory count when it comes to the secondary benches in the Bone Springs? And how does your success potentially push the inventory count higher?

Yes. I'll just, maybe give you some perspective on how we're thinking about our inventory in general in terms of how that's going and I can address some of the Bone Spring. So the last couple of years, we've been able to more than replace the wells drilled with improvements in inventory, which come in 2 buckets. One is appraisal activity, which I'll give you a little color on in terms of Bone Spring to your question but also production improvement and cost reduction. So both of those things, not only add inventory but they move it, we call it to the left, that gets us to less than $60, less than $50 and then ultimately what we're going for less than $40 breakeven inventory. And so as we think about, this year in the unconventional, we had a target of around adding 450 wells in the unconventional less than $50 breakeven. A bulk of that will come from -- we highlighted, one of the highlights we had was this third Bone Spring target that we had on the slide highlighting the 4 wells with greater than 780 MBOE or MBO. Those will add a bulk of our improvement this year in terms of that promotion of inventory. And so when I look at, even in the first quarter, just to give you some color, so we're aiming for this 450, in the first quarter we had 90 adds less than $50 breakeven. That came, about half of that, from the Bone Spring wells that I mentioned but we're also getting things out of New Mexico and some of the shallower Bone Spring there. And so it's not only what we're drilling today, which is going up in terms of secondary benches as a percentage of our total drilled wells in the year but it's really adding that low-cost inventory in the future. And so a lot of times, we'll get the so what of this inventory and that's really it. It's being able to extend this low-cost capital intensity as we prosecute our plan over the next few years.

Got it. And then how do you think about potentially codeveloping some of the Bone Springs, along with the core Wolfcamp? Or you're mainly looking at coming back and hitting those zones, leveraging the installed infrastructure as you mentioned?

Yes. I think -- I mean that's a big part of, I'd say the next few years, is really optimizing how we put that together. Obviously, in the Midland, we do a lot more what we call co-development where you're doing these zones at the same time. One of the benefits in the Delaware is being able to sequence them, have a little bit more precision because of the frac barriers. So we don't have to think about more of the [ cube ] or co-development opportunities, which gives us a great opportunity to really maximize the savings we get from reusing these facilities, like I described. So last year, I think we were around 20% secondary benches in the Delaware. This year, we're north of 30%. So you can see that sort of opportunity becoming more prominent in terms of our development plans.

The next question comes from Nitin Kumar with Mizuho.

I just want to start on CrownRock quickly. You mentioned that you're still on track to close the deal in the third quarter. When we announced the deal, you had talked about 170,000 BOE per day of production from CrownRock. Just wanted to see if you could revisit that and see how things are trending there as you are getting closer to the close?

We don't really have any update on the -- either the production or any of the other metrics from CrownRock, just what we've provided previously. We'll probably provide -- we'll definitely provide an update when we have our next quarterly meeting. Because by that time, I believe, we will have closed, maybe not but it's going to be certainly sometime in the third quarter.

Great. I thought I'd take a shot. And just -- there's been some movement in Colorado around SB24, which requires a production fee on producers. Want to see what that would look like for Oxy? You're a big producer in the state and sort of what your thoughts are around that initiative?

Yes. I think that the agreement that was reached in Colorado was a win-win for both the people of Colorado and the investments -- the investors in Colorado. So we feel that paying the fee and along with paying the fee to have taken away some bills and some potential ballot measures that would have severely restricted what the oil and gas industry could do that when you take that together, all together, it provides a scenario for the governor and the government of Colorado to do something positive with the fees that will be collected. So we view this to be not overly burdensome for our operations. We think it's actually going to be a doable scenario for us as we work towards some of the other things that will come along with this, which is working more on doing things that impact and help to reduce the impact on the ozone layer, as well as doing some things that will help from an environmental justice standpoint. So it's a full package deal. It's not just a fee. And putting all that together, it's a good deal.

The next question comes from David Deckelbaum with TD Cowen.

I wanted to ask for a little bit more color just on the guide just so I'm clear on how numbers are progressing this year. The impact from the Gulf of Mexico, is that exclusively what's contributing to the 100-basis point reduction in oil cut this year? Are you seeing some contribution from some gassier zones and some other of your core assets or perhaps the impact of the PSE in areas like Algeria?

No, it was almost entirely due to the Gulf of Mexico shutdown. There's really nothing else trending differently that we have in our portfolio.

Appreciate that. And then maybe just a follow-up on the discussion around deleveraging and noncore asset sales. It sounds like on this call, you might be emphasizing more the cash flow returns that you would be otherwise receiving from some of these assets that maybe the market has flagged as divestiture candidates. Is that the intention here in signaling that you intend to delever more organically in that noncore asset sales either theoretically would be higher in dollar value to reflect that cash flow contribution or might take longer to materialize?

I don't think that's what we intended to say. That was not the message we intended to give. When we talk about the fact that we will evaluate everything from a value perspective, what we want to do is just ensure that we're making the right decisions and divestitures of noncore areas is something that we want to do. And we believe that based on the interest that we're seeing that we should be able to achieve.

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

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

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