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Presentation

Operator: Good afternoon, and welcome to Occidental’s Fourth Quarter 2022 Earnings Conference Call. Please note, today’s event is being recorded. I would now like to turn the conference over to Neil Backhouse, Vice President of Investor Relations. Please go ahead.

Neil Backhouse: Thank you, Rocco. Good afternoon, everyone, and thank you for participating in Occidental’s Fourth Quarter 2022 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Rob Peterson, Senior Vice President and Chief Financial Officer; and Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management. 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. Vicki, please go ahead.

Vicki Hollub: Thank you, Neil, and good afternoon, everyone. On today’s call, I’ll begin with highlights of our 2022 achievements, including an oil and gas update followed by our fourth quarter performance. Next, I’ll discuss our 2023 cash flow priorities, our enhanced shareholder return framework and our 2023 capital plan. Rob will then provide an update on the status and mechanics of Oxy’s preferred equity redemption before reviewing our fourth quarter financial results and 2023 guidance. In 2022, our record net income of $12.5 billion, generated a return on capital employed of 28%, which is the highest return we have achieved since before 2005. We also delivered record free cash flow before working capital of $13.6 billion, which enabled us to retire more than $10.5 billion of debt and to repurchase $3 billion of common shares.

Our return on capital employed was enhanced by exceptional performance as our team set multiple operational and productivity records across our U.S. onshore, Gulf of Mexico and International businesses. OxyChem generated record earnings in our Midstream business approximated guidance. Also in 2022, our high-return Permian production grew by 90,000 BOE per day, propelled by outstanding well results. We delivered our best year ever in Delaware new well productivity, 2022, the seventh year in a row that we were able to increase our average well productivity, as shown in our presentation’s appendix on Slide 29. Our teams accomplished this by applying our proprietary service modeling and completion designs to our high-quality reservoirs. Well performance, along with our Oxy drilling dynamics and logistics efficiencies, enabled us to achieve reserves replacement ratio driven by our capital programs of over 140% at a cost of $6.50 per BOE, which was less than half of our current DD&A per barrel.

With price revisions included, the total reserves replacement ratio was 172%, which increased our year-end 2022 reserves to approximately 3.8 billion BOE. Except for the years of the price collapse in 2015 in the pandemic in 2020, we have replaced more than 100% of our production for at least the last 20 years. With the depth and quality of our shale well inventory and 2 billion barrels of remaining potential in our Permian enhanced oil recovery business, we have the scale to continue our history of reserves replacement. A deep inventory, along with our unique portfolio of short-cycle, high-return unconventional assets paired with low decline conventional assets, OxyChem and our Midstream businesses, we have the capability for long-term sustainability and the flexibility to allocate capital to maximize returns for our shareholders.

In 2022, we also made significant progress in developing the capabilities and assets needed to secure a low-carbon future, which is the other key to our sustainability. We started site preparation on our first direct air capture plant and executed several exciting agreements to sell carbon dioxide removal credits to prospective purchasers and industry — diverse industry sectors. We also secured over quarter million acres of land or approximately 400 square miles to develop carbon sequestration hubs. The fourth quarter of 2022 was a fitting way to wrap up a year of continued operational and financial success. We generated over $2.6 billion of free cash flow, which supported nearly $1.6 billion of balance sheet improvements. We also repurchased $562 million of common shares in the quarter, completing our 2022 share repurchase program.

In our business segments, Oil & Gas approximated the midpoint of guidance, despite winter storm Elias impact. Outperformance from the Gulf of Mexico and Al Hosn partially offset storm impacts experienced in the Permian and Rockies. OxyChem exceeded guidance, driven by stronger-than-expected market dynamics, while Midstream and marketing earnings were within guidance. In December, Oxy participated in the recapitalization of NET Power. This is a technology that generates emission-free power generation and has the potential to accelerate emissions reduction efforts in our existing operations and to supply electricity to our direct air capture plants and sequestration hubs. Ultimately, NET Power could be an important emission-free power generator anywhere that has access to natural gas.

Among the record set in 2022 were lateral lengths in the Delaware Basin, DJ Basin, Oman and most notably in the Midland Basin where our well Lulu 3641 DP exceeded 18,000 feet to become our longest lateral on record. Remarkably, this well was drilled in slightly over 12 days. Milestones like this showcase our team’s focus on safely and efficiently expanding the boundaries of drilling technology. Our teams also achieved an Oxy Delaware Basin record for wedge productivity, averaging a 30-day initial production rate of over 3,000 BOE per day from all wells that came online in 2022. We believe that 2 of our wells in the First Bone Spring in New Mexico and 6 of our wells in the Barnett formation of the Midland Basin achieved initial 30-day production records amongst all operators in their respective formations.

In addition, we are continuing to consolidate acreage via trade that enable more capital-efficient, longer laterals, which help to optimize the required infrastructure. The longer laterals, exceptional well productivity and optimized infrastructure, partially offset inflation impacts in 2022, and we expect similar benefits as we progress through 2023. After highlighting 2 of our Gulf of Mexico assets, Horn Mountain and Caesar-Tonga on previous earnings calls, I’m pleased to announce another Oxy production record in our offshore operations. Our Lucius platform surpassed 150 million BOE of gross production in less than 8 years from first oil, becoming the fastest Oxy developed Gulf of Mexico platform to reach this milestone. Internationally, we, along with our partner, ADNOC, achieved record quarterly production at Al Hosn with 85,500 BOE per day net to Oxy.

The Al Hosn expansion project is progressing well and remains on track for mid-2023 completion. We expect Oxy’s Al Hosn net production to ultimately reach approximately 94,000 BOE per day. We are pleased with the total value we’ve created for shareholders in 2022, including the debt reduction of $10.5 billion and the $3 billion of share repurchases, along with a successful capital program of $4.5 billion. With our debt from outstanding bonds down to less than $18 billion and consistent with our shareholder framework, we will shift our focus to share repurchases, dividend growth and a capital program that further strengthens our sustainability. Over the long term, we intend to repay maturities and opportunistically retire debt to further reduce our cost structure and strengthen our balance sheet.

In future years, we will seek to grow our cash flow and earnings to support increases of our dividend and the continuation of our share repurchase program. While we do intend to grow the absolute value of the company, as part of our value proposition, we also want to increase value per share for our shareholders through dividend growth and the reduction of outstanding shares. Accordingly, our Board of Directors authorized an over 38% increase in our common dividend and a new $3 billion share repurchase authorization, which will trigger a redemption of a portion of the preferred equity. Future cash and earnings growth opportunities could come from our shale and conventional oil & gas assets as well as our chemicals business and ultimately, our Low Carbon ventures business.

Turning now to 2023. Our business plan is designed to maximize return on capital and return of capital to our shareholders while also strengthening our future sustainability by prioritizing asset-enhancing investments to support the resilience of Oxy’s future cash flows. These investments include $500 million for low decline mid-cycle projects, including the previously announced modernization and expansion of OxyChem’s Battleground chlor-alkali plant and a new OxyChem plant enhancement along with Permian EOR in the gulf of Mexico. Of the $500 million that I just mentioned, we plan to spend $350 million on OxyChem projects, which upon completion, we expect will generate a combined annual EBITDA of $300 million to $400 million. We expect the Battleground project to be online in early 2026.

The other OxyChem plant enhancement will deliver higher production volumes, enhanced operational efficiency and improved logistics costs. We look forward to providing more detail about this project on a future call. The remainder of the $500 million will be spent in EOR in the Gulf of Mexico. EOR remains a core component of Oxy’s asset portfolio and will be essential for our future strategy, so we are glad to return to sustaining capital investment level this year. In the Gulf of Mexico, infrastructure projects, including subsea pumping initiatives to increase the tieback radius and productivity of the existing platforms, will drive higher capital spending compared to recent years. We’re also focused on our high-return short-cycle businesses.

I returned to a 2-rig program in the DJ Basin late last year requires additional investment but should begin to moderate production decline by the middle of 2023. In our Permian unconventional business, we intend to run an activity program similar to the second half of last year. Our Permian unconventional assets are best placed to deliver production growth to offset marginal declines elsewhere in our portfolio. Overall, 2023 Permian unconventional capital is expected to decline slightly from 2022 due to the initial capital inflow from the Delaware Basin JV. We anticipate that inflation will continue to be a challenge for our industry this year. In 2023, we expect approximately 15% inflation impact on our domestic Oil & Gas business compared to 2022.

As always, we will continue our efforts to reduce and offset inflation by leveraging our supply chain competencies and focusing on continued capital efficiency. Another important aspect of sustainability is the carbon intensity of our operations and what we’re doing to address it. We focus on reducing emissions every day as we progress our pathway to net zero. And we’ve made significant progress over the past few years. Since 2020, our emissions reductions projects have focused on capturing methane and reducing venting and flaring. These projects resulted in a 33% decrease in our estimated company-wide methane emissions from 2020 to 2021 and a 24% decrease in methane emissions intensity of our marketed gas production. We were the first U.S. oil & gas company to endorse the World Bank’s Zero routine Flaring by 2030 initiative, and I’m pleased to announce that our U.S. Oil & Gas operations achieved Zero Routine Flaring 8 years ahead of that target.

That was a major achievement. Our international operations have implemented projects to significantly reduce routine flaring, and we’re on track to meet the World Bank’s target well ahead of 2030. In 2023, we also intend to invest in several unique and compelling Low Carbon business opportunities to advance our net zero pathway. Ongoing construction of our direct air capture facility in the Permian and the development of our large Gulf Coast sequestration hubs, including Pore space certification, will be among our expected investments. We anticipate that our first direct air capture, or DAC, plant will complete commissioning and begin to capture carbon in late 2024 and be commercially operational in mid-2025. This timing is a few months later than our original target.

As we navigate the current supply chain environment and focus on construction sequencing to support faster optimization and the application of new technologies and innovation. Our 2023 capital investment in these Low Carbon businesses is expected to total $200 million to $600 million, subject to third-party funding optionality for the DAC and the timing of projects. We mentioned on our prior call that our net zero ambitions will our funding outside of Oxy’s historical capital allocation program. However, we are prepared to fund our first stack ourselves if utilizing our capital preserves the most value for our shareholders. Our capital plan includes investments in our carbon sequestration business, both through the development of the Gulf Coast hubs we previously announced and through drilling appraisal wells.

Investments in other projects that reduce Oxy Scope 1 and 2 emissions will also continue. As part of our strategy to develop Gulf Coast sequestration hubs, we’re pleased to announce that we will be working with energy transfer low-carbon development to build a pipeline network from point source emitters in the area through our Magnolia sequestration site in Allen Parish, Louisiana. This pipeline will support our point source carbon capture and sequestration business, which we intend to develop along with our DACs, to help medium- and long-term greenhouse gas emission reduction goals for Oxy and our customers. Before turning it over to Rob, I want to reiterate that our 2023 capital plan focuses on projects that best position Oxy for long-term success.

As in past years, we retained a high degree of flexibility, which allows us to adapt to commodity price fluctuations and reduce spending if necessary. Now I’ll turn the call over to Rob.

Robert Peterson: Thank you, Vicki, and good afternoon, everyone. Last year, we repaid over $10.5 billion of debt and retired all remaining interest rate swaps, breaking on our balance sheet and improving our credit metrics as we seek to regain investment-grade ratings. The completion of our $3 billion share repurchase program moved us closer to returning over $4 per share to our common shareholders, which will begin to trigger a redemption of the preferred equity. Our fasting improved financial position, even compared to 1 year ago, enables us to begin allocating a greater proportion of excess free cash flow to our shareholders in 2023. Today, I’ll begin by explaining where we are in terms of partially redeeming the preferred equity, I’ll then detail our redemption mechanics in a scenario where the $4 trigger is met.

The mandatory redemption of deferred equity is triggered with a rolling 12-month common shareholder distribution, which a cumulative $4 per share. This trigger is evaluated daily based on shares outstanding on the day capital has returned. As of today, we have distributed $3.70 per share additional $0.22 per share is required to reach the $4 trigger. In our presentation, we have included an illustrative example of a $100 million distribution to common shareholders after the $4 share trigger is reached. In conjunction with the common distribution, a $100 million mandatory matching distribution versus a half that will be made, of which $91 million will redeem preferred equity principal with a $9 million or 10% premium. In this example, Oxy would incur a $200 million total cash outlay.

This process of mandatory redemption repeats as long as the trailing — or, share trailing 12-month distribution to common shareholders is greater than $4. There is no limit to exceeding the $4 per share trigger through additional distribution to common shareholders. Consequently, even if the trailing 12-month distribution decline, additional distribution to common shareholders will still trigger partial preferred equity redemption. We expect our refreshed share repurchase program to combine with our $0.18 per share quarterly dividend to enable us to exceed the $4 per share trigger to begin redeeming the preferred equity. While the magnitude and pace of the partial preferred redemption and resulting enterprise value balancing will ultimately driven by commodity prices, we expect our shareholders to benefit in a similar way to the value created in 2022 through debt reduction.

I’ll now turn to our fourth quarter results. We posted an adjusted profit of $1.61 per diluted share and a reported profit of $1.74 per diluted share. Difference between adjusted and reported profit was already driven by a noncash tax benefit related to new organization of legal entities. As Vicki mentioned, our Board recently authorized a new $3 billion share repurchase program following the repurchase of approximately 47.7 million shares last year for a weighted average cost of below $63 per share. We exited the quarter to approximately $1 billion of unrestricted cash after paying $1.1 billion of debt and retiring $450 million in notional interest rate swaps. For the year, we completed over $10.5 billion of debt repayment, which eliminated 37% of outstanding principal and resulted in a sizable reduction in interest rate — interest burden.

We estimate that the balance sheet improvements executing in 2022 will reduce interest and financing costs by over $400 million per year. Our proactive debt reduction efforts leveled the company’s profile of future maturities and so that we now — so we have less than $2 billion of debt maturing in any single year for the remainder of this decade. Going forward, we intend to repay debt as it matures and may also reduce debt opportunistically. We repaid approximately $22 million in January and do not have additional maturities until the third quarter of 2024, providing us with a clear runway to focus on returning cash to shareholders and partially redeeming the preferred. In the fourth quarter, we generated approximately $2.6 billion of free cash flow, even with inflation continuing to pressure costs and capital spending.

Domestic operating expenses were higher than expected, primarily due to the impact of winter storm Elliott, equipment upgrades and platform life extension work in the Gulf of Mexico and inflation. Overhead increased as a result of higher accruals related to compensation and annual environmental remediation. Capital spending in the quarter was higher than expected due to inflationary impacts, investments in attractive OBO projects, scheduled changes leading to activity in higher working areas and rig starts for our Delaware JV. We further improved our liquidity position when Oxy became the first company ever to securitize offshore oil & gas receivables and an amendment to increase our accounts receivable facility by 50% to $600 million. In 2022, we paid U.S. federal cash taxes of approximately $940 million, in line with our previous estimate.

As we move into 2023, we expect to have full U.S. federal cash taxpayer as we’ve utilized all our NOLs and U.S. general business carryforward credits. We expect our full year production to average 1.18 million BOE per day in 2023. As it was the case last year, production in the first quarter is expected to be lower than the preceding quarter due to scheduled maintenance turnarounds, primarily in our international operations. We’ll have fewer wells come online in our U.S. onshore business in the fourth quarter, with only about 15% of our Permian wells and 6% of our Rocky wells for the year turning over to production. That said, our overall production trajectory is expected to be smoother in 2023 than the prior year. Throughout 2022, we worked with Colorado regulators and local communities to successfully navigate the permitting process.

Our work positioned us to add back 2 rigs in the DJ by the end of 2022. Given the reduced activity levels over the last few years, our Rockies production is likely to be lower in 2023 last year. Production is expected to stabilize in the second half of 2023 once the benefits from the additional rig picked up in the fourth quarter of last year fully materialize. rules in Colorado typically lead to a pad development approach with a linear time to market cycle as compared to simultaneous operations in other shale plays. This operating environment creates negligible additional costs for our development, but this year is expected to have a noticeable impact on time to market as our activity ramps up. The DJ Basin remains an exceptionally high return asset for Oxy, and we welcome the return of sustaining capital levels to that business, which was predicated by the regulatory certainty and permitting efficiency we are now experiencing in Colorado.

The production sharing contract we announced last year with Algeria is expected to take effect in March. Once the agreement is in place, net barrels to Oxy will decrease by approximately 15,000 BOE per day, which is reflected in our 2023 guidance. We do not expect a material change in operating cash flow because the tax rate were also reset under the new PSC Operating costs across our Oil & Gas business are expected to approximate the second half of 2022 as inflationary pressures remain in our lower-cost DJ Basin production declines. In the Gulf of Mexico, maintenance work to further reduce plan time — planned downtime and extend platform lives will impact operating costs. We are also increasing EOR downhole maintenance work and CO2 purchases.

On a BOE basis, operating costs may increase internationally due to lower reported barrels of the new Algeria contract. 2022 was an exceptional year for OxyChem as the business exceeded $2.5 billion in income. We expect 2023 to be another strong year by historical standards, that is unlikely to match 2022. Caustic soda prices reached all-time highs in the fourth quarter of 2022, but we are now making downward pricing pressures as the macroeconomic environment remains uncertain. PVC pricing fell sharply in the second half of 2022, but has begun to stabilize. As I’ve mentioned before, OxyChem’s integration across multiple chlorine derivatives enables us to optimize our production mix to what the market demands. We remain optimistic about the business, and our capital investments will further strengthen our margins and competitive position.

Looking forward to the rest of 2023 and beyond, we remain dedicated to extending the success of 2022 and advancing our enhanced return framework. I will now turn the call back over to Vicki.

Vicki Hollub: We’re now ready to take your questions.

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Operator: And today’s first question comes from Raphaël DuBois with Societe Generale.

Raphaël DuBois : The first one is about the DAC 1 timing, which seems to have slipped a little bit with operating status now to be reached mid-2025 instead of end 2024. And I was wondering if we should consider that it’s — it means that other DACs, the ones that follow could also be delayed. That will be my first question, please.

Vicki Hollub: No, we don’t expect delays in the other DACs. The delay came because of the supply situation that we’re experiencing today. We expect that since those are further out, we’ll have more time to prepare and to address some of the supply chain challenges that we have today. So we don’t expect the schedule to change.

Raphaël DuBois : Great. And my follow-up is on the $200 million to $600 million CapEx for the Low Carbon. Can you maybe help us better understand why is dedicated for that one? And what is left for other projects?

Vicki Hollub: We haven’t broken out the — that $200 million to $600 million at this point. Richard, do you have anything?

Richard Jackson: Yes. I was just going to add, I mean, to kind of help give you some color on the program. I mean, certainly, some of that is allocated as we started construction for DAC 1 this year and obviously continue on the next couple of years with our construction pace. We do continue to develop our CCUS hubs around the Gulf Coast that we’ve previously disclosed, and we announced with the Midstream partnership today. And then the other piece, and I think it partially answers your first question is continuing to look at our DAC Pre-FEED and FEED work as we go into the South Texas hub. We think that’s meaningful. And so while we’re progressing and optimizing the schedule for DAC 1, in parallel, we’re working with the same innovations and learnings and applying that to our South Texas Hub, which we think we’ll be able to keep us on pace for that development as well.

Operator: And ladies and gentlemen, our next question today comes from David Deckelbaum with Cowen.

David Deckelbaum: I wanted to dig in a little bit more. You talked a bit about reaching this $4 per share return on capital threshold and now looking at the preferreds as this trigger as a priority. How do we think about your view on the returns of capital on retiring preferred versus, say, supplementing that with asset sales as we work through the year, especially as you get beyond the second quarter of ’23 and that trailing 12 months $4 a share benefit kind of rolls off, especially from that notable lump in the second quarter of ’22? How do you think about navigating that? And should we expect you to kind of pull forward other sources of cash to try to stay above that threshold?

Vicki Hollub: Hitting the threshold has been really not a target, but an outcome of a plan that we wanted to execute anyway. Share repurchases is such a critical part of our value proposition that this is the way it has evolved. We’re not really sure what the macro is going to do towards the end of this year. So in terms of what if any asset sales we would do to keep the pace, that really is dependent on the value — what value we see in doing that and what we have available. But I would say right now, we don’t have anything on the list to sell. Of course, anything we have is for sale, it’s for the right price. But there’s nothing that we’re actively marketing right now. And we believe that the second half of the year could potentially bring a macro environment that allows us to continue without engaging in any additional asset sales.

David Deckelbaum: That’s helpful. Maybe if I could switch just to the second quickly around Low Carbon ventures and DAC. There’s obviously some funding that’s been made available under the Bipartisan Infrastructure Law. It seemed like you alluded to some flexibility in the budgeting around DAC for potentially other sources of funding. Can you walk us through maybe the application process and the time line for how we might think about any potential loans that would be coming through or when we might have some more information around other sources of funding?

Richard Jackson: David, this is Richard. I’ll try to answer a piece of that. Really, two pieces, as you described. I mean we continue to have good discussions with capital partners, not only for DAC 1, but as we look at capitalization over the life of our development plan. And so that’s an important part that we want to stay fresh with. The second part is, as you mentioned, some of the grant programs that are directly associated with CCUS and DAC specifically. We’re not in a position to talk in detail on that today, but we are and — have communicated before, we think our projects fit very well. The intent of that program. We think the — really the advanced design and really state that we’re in as we go into DAC 1 and then into the South Texas Hub puts us in a really good position for that type of program.

I think the South Texas Hub, as you look at that, in particular, it’s just a unique opportunity to look at sort of the large-scale build-out when we’ve contemplated the 30 DACs for that area. So to directly answer your question on updates, I think we’ll have more as we go this year, but we’ll leave it at that for now.

Operator: And our next question today comes from Jeanine Wai with Barclays.

Jeanine Wai: I have two questions, I guess, around the Permian, if we could. The first one, maybe on inventory. The second one on sustaining CapEx. On inventory, we compared your updated slide versus the prior version. And after adjusting for wells to sales in ’22, it looks like the location count for the wells that break even for under 60. It really isn’t all that different, which implies about a 16-year inventory at the current pace. So just wondering if you can talk about any of the differences in assumptions between the old and the new inventory calculations, whether it’s on cost or on development strategy? For example, we saw in the footnote there that your updated inventory uses the ’22 budgeted well cost. And how different would that look if you use current costs?

Richard Jackson: Great. Jeanine, this is Richard. I’ll try to help answer a few of those. I mean very proud of our inventory obviously good acreage position that we have and have accumulated, but very pleased with the team’s ability to continue to advance that. So as you noted, especially in Permian resources strong less than $60 breakeven with long activity, I’d say some of the changes that have occurred, we tried to highlight one even in that slide is really thinking about longer laterals. So able to continue to core up acreage where we’re at be patient in development areas to allow that to happen and really sequence our developments to accomplish the longer lateral. So as we were able to do that, obviously, that may go down one, but we’ve made a much more valuable single well inventory.

The other thing I would say is just really the environment over the last couple of years, as we restated capital or began to put capital back into the program since 2020. That’s allowed us to really develop some new areas in zone. So for example, the First Bone Springs wells that we noted, very proud of those. What happened during that under investment cycle, we continue to work the technology and the development plans to really advance those zones. And so those type advancements in areas and zones like that also are adding to our inventory. But that restoration and capital, we believe this year especially will allow us to further advance our inventory. For example, we have 40 target wells in 2023 that we believe will fully replenish the wells we drill this year.

And so we’re pretty thoughtful in terms of how we’re expanding that and approaching that inventory. And so hopefully, as we go, that will continue to grow in the Permian. But even in areas like the Powder River Basin, we’re resuming some activity this year.

Jeanine Wai: Okay. Great. Moving to the sustaining CapEx In the $3.5 billion sustaining CapEx estimate, how much of that is allocated to the Permian? And does that keep Permian production flat versus ’23 levels? We know Oxy has got a ton of different operating areas, and there’s a lot of different ways to keep production flat there?

Vicki Hollub: Yes. When we think about sustaining capital levels, it’s really how do we maximize the return on capital employed for each of the assets that we have, while ensuring that we could do that for on a multiyear basis. And for example, when you talk about the Permian, there’s the resources part of the business and the EOR part. The EOR part, the way we’ve been able to maximize return on capital employed for it is to actually keep the facilities fully loaded all of the time. So we’re not — we don’t have unused capacity and keeping those facilities fully loaded requires a certain level of capital. We certainly have the potential to continue to grow the EOR business beyond that. But up to this point, that’s what we’ve been able to do to get the most value out of it.

The Resources business, combined with the AUR business, would require about $1.8 billion for sustaining capital. And this year, we did increase the EOR and that’s part of the reason to do that is that the lower decline of our EOR business, the lower decline of the chemicals business and our gas flow assets in the Middle East those are critically important to us. And as you know, we’re expanding Al Hosn, which will very — not by very much. will that increase the sustaining capital there, but will provide us additional low decline cash flow from that asset as well. And that’s what we most like about our portfolio is that this diversity of having the lower decline assets combined with the higher decline, but higher cash flow generating assets in least initially is very complementary.

So we have the best of all worlds, I think, in the diverse portfolio that we have.

Operator: And our next question today comes from Matt Portillo with TPH.

Matt Portillo : Just maybe to start out, I was hoping to see if you could give us an update maybe how things have progressed since the LCB Day on the PointSource business, maybe some of the conversations you’re having with the IRA Bill coming out? And any color that we may be able to look through on when the first project might start up and how you guys are thinking about kind of the total volumes you’ve secured so far for sequestration on point source.

Vicki Hollub: Okay. Thank you for the question. I’ll pass that to Richard.

Richard Jackson: Yes. Great. Matt, I think things for many of us in CCUS and certainly in the U.S. are progressing well post IRA. I think lots of work going on with emitters to transport to sequestration. Our focus really has been sort of similar to oil & gas, really working to secure the best sequestration sites and develop those in a way to be both large scale, so we can get the economies of scale, but also be able to provide that certainty as these deals are putting together. So we have really 5 hubs that we’re working that we’ve talked about. We’ve got several Class VI wells in progress as well as characterization of these sites. The Midstream providers are very important. And so being able to secure those partnerships early, I think, aligns really the downstream from the capture site to be able to do that.

So as we think about sort of how this plays out over the next couple of years, we’re hopeful that as we go this year more projects will be able to combine that capture to transport the sequestration and really hit FID and then begin construction over the next couple of years. I think our work even going back to some of the work that we’ve done in the Permian over the last several years around some of the capture projects there really helped inform us. Hopefully, as a good partner about how do you manage that kind of across the value chain. And so our focus is, again, really on that sequestration. That really puts us in a good position to take together the synergies with DAC as we develop that. And so we’re playing that role and having good conversations towards those projects.

And again, expect this year to have more updates.

Matt Portillo : Great. And then as my follow-up, just around OxyChem, a strong start to the year with the Q1 guide. Just curious if you all are feeling about the outlook for caustic and PVC and maybe what’s baked into the guidance expectations as we progress through 2023?

Robert Peterson: Yes, sure, Matt. So what we end for the year was domestic PVC demand was actually down about 6.8% in ’22 relative to ’21. But what we did — was we saw as an industry that export demand ended up being about 46% higher the total PVC demand actually grew almost 7% year-over-year in ’22. And so we’re looking into what’s going on and what’s in our guidance is we saw that softness in PVC through the fourth quarter, but it appears that bottomed out late 2022, early 2023. So all PVC buyer adjustments we believe were largely completed as prices were falling. And we believe that, as we sit here today, that many buyers inventories are low as we enter construction season. We’ve also seen PVC export prices not only bottomed but are actually starting to trend upward most recently.

And in the domestic market, all the producers have significantly announced price increases in the domestic market for PVC. So thinking about the guidance in PVC, it reflects the uncertainty of the trajectory of the domestic and global economy that’s going to drive that business. And so while there’s still this huge pent-up demand we see in construction and the low inventories, there’s still headwinds from the impact of the higher interest rates, which now may not peak as early or begin to subside as quickly as anticipated. And of course, the pace of economic activity increases in China is just going to continue to be an impact to the DTC business globally impacting trade flows for PVC. So that’s what’s factored into this kind of murky outlook for PVC.

The caustic soda business, we saw export prices, I discussed in my early comments decline, not just from the impact of the global economy from the China taking, again, longer to restart, but also European markets stocked up significantly on caustic soda as we went into winter. That certainly has started to loosen from tight market conditions to looser market conditions and we operating costs come down dramatically in Europe as energy prices have fallen. Our guidance on the caustic side of the business, this assumes it’s going to take time for this unwinding of European inventories and a gradual opening of the Chinese economy. So — but again, I would say, as we’ve talked in the past, our chemical business is so heavy weighted in domestic construction and global GDP.

We’re going to know a lot more about the total trajectory of the year than we do and sitting here in February than we will, maybe in May or June at that time. We’ve got a couple more months to look at it. So Overall, that guidance for the year just reflects that uncertainty around both sides of the business at this point.

Operator: And our next question today comes from Doug Leggate with Bank of America.

Doug Leggate : First of all, apologies. I was a little late getting on, so I hope my questions haven’t been asked already, but a lot going on today. Vicki, I want to ask about the Gulf of Mexico trajectory and the cash operating cost. It seems to me at least that this is an area where we’ve always had a little bit of — it’s been a bit murky to understand just what the decline in the development backlog looks like from the legacy portfolio. But it seems that you are doing a lot better on the production guide and the trade-off maybe is a little bit higher OpEx. Can you give us your latest thoughts on what you see as the trajectory longer term for the Gulf?

Vicki Hollub: Our plan for the Gulf of Mexico is to continue to keep it at around the production rate that it’s at right now. It’s, as you know, a significant cash flow generator for us. So we have the inventory, and we have the plan laid out to ensure that we can — we have the development ready to to maintain the current level of production where it is. We don’t intend to significantly grow production. That could be part of the outcome of what some of the exploration and development will lead to. But it’s our intent and it will be lumpy. As we’ve said before, capital there will depend on our exploration successes, how those go and timing. But on the average, our production level should be about where it is today.

Doug Leggate : For what period?

Vicki Hollub: I would say that we just picked up some leases, as you know. We’re now doing the preliminary work on those leases. I would say that our trajectory is certainly between — somewhere between 5 and 10 years of potential inventory to maintain what we have today.

Doug Leggate : That’s helpful. My follow-up is a favorite question of to be predictable, but I want to ask about your breakeven, but new onset a little bit. Obviously, we’ve had some inflation, your breakeven capital. What you’ve recognized today? And I guess, what I’m really trying to understand is how you think about dividend capacity as part of that breakeven, let’s say, it’s $40. Has that become like a ceiling for your dividend thoughts? And I guess the clarification point, if I may, Vicki, there’s been a lot of questions today about DAC, obviously. When you think about that breakeven, are you including the capital or sustaining capital for the DAC business as well?

Vicki Hollub: Well, certainly, I would say that we are not including the capital for the DAC as a part of our breakeven or sustaining capital. If we were in a scenario where we were down in a $40 environment, unless we had significant capital inflow from somewhere else, we would significantly cut back our development on the DACs unless that development was supported by others. So I would say that when you think about the breakeven for us and I kind of wish we had never brought that term up because it’s so misleading to people. We — I would say the difference in where we are today, where maybe we’ve been in prior times is that we keep a model of what it’s going to take to support our dividend at various oil price levels. And what we’ve said is still true that we want to ensure that we’re close to a $40 breakeven or less so that if we’re in that environment that we can still sustain the dividend.

I never want to go through a scenario where we would have to cut it again. But what that breakeven really is, what would the price and the world look like at $40. So you can’t take our numbers right now and back into what it would be and expect it to be $40. We’ve obviously elevated our capital investment higher than than what it would be, what the calculation would show the breakeven is today. So breakeven for us means that if you’re in a $40 environment, then the supply chain, the services and materials, all of those things would be adjusted to that kind of environment to that cost. And in that environment, our cost would then be less than it is today on OpEx and even labor cost, services materials — So in that environment, we look at what would it take to ensure that we could sustain our dividend growth.

And that’s how we would calculate that. So — and that — and sustaining capital is different. As I explained earlier, sustaining capital is where you have every asset, the investment level at the point where you’re generating the best returns that you can generate from the infrastructure and facilities that you have and the resources that you have. So with what we’re doing today, as we continue to reduce our cost structure as we continue to lower our interest from our debt reduction, and we’ve as we will buy back some of the preferred, we’ll lower that cost as well. We use those two measures as the primary way we can calculate how much we can grow our dividend. So as we’re continuing to reduce interest as we’re continuing to reduce the preferred dividend, that will be the capacity available for the growth of the dividend.

And to further get it to increase it on a per share basis, our share repurchase program is intended to help with that as well. So it’s an absolute number cap that we have as well as a share repurchase program that allows that dividend per share to continue to increase over time.

Operator: And our next question today comes from Paul Cheng with Scotiabank.

Paul Cheng : Two questions, please. If — I have to apologize. I want to go back into the inventory. That number, how that will change for those that less than $50 WTI and we changed the Henry Hub gas by to 2 50 and the internal way of return to, say, 15%, 20% and also for the cost, I mean how that is going to get changed? That’s the first question. And the second question that I think a lot of your peers that — or at least some of them have signed the LNG supply agreement and one of your largest peer actually make investment — equity investment in the LNG plan. Want to see if Oxy think that, that will be a suitable investment for you? And what is the game plan there?

Vicki Hollub: I’ll take the LNG question first as Richard is pondering the other question. The LNG question, one of the things that we’ve always tried to do is make sure that we do things that are within our core competence. And so our core competence is getting the most out of oil & gas reservoirs and handling CO2. So LNG is not something that we would want to be a builder of. And if it’s something that we don’t want to be a builder of or use as a part of our strategy in our oil & gas development and . If it’s not a part of that, that’s not something that we would put our investment dollars in. We’re not going to go too far from what we know how to do the best.

Richard Jackson: Paul, this is Richard. I try to answer your question on the inventory. I mean, as you think about sort of a discount rate against that inventory, obviously, if it’s higher, that would change the numbers a bit, but we are still very strong in that inventory. For example, in the DJ as we think about that program and we look at gas price fluctuations, we look at plus 50% type program returns even at a lower gas price than what we show there. So it will impact things. But I think in terms of the strong returns that we have will exceed sort of our expectations on return on capital. And we continue to manage that inventory to drive really what we develop into those lower breakeven categories. Probably the other thing to say on that, basically, the inventory this year with the wells that we drill are all less than $40 breakeven.

So we’ve been able to high grade ahead of time to make sure that we have sustainability of those returns. And as I mentioned earlier, the wells that we targeted to replenish 100% of our drilled wells this year, we’ll expect to carry that same result.

Operator: And our next question today comes from Roger Read with Wells Fargo.

Roger Read: I’d like to follow up really, I guess, on the Gulf of Mexico, maybe secondarily, on the EOR side. Relative capital discipline or maybe even aggressive capital discipline over the last couple of years for the obvious reasons. Just wonder how you’re comfortable in terms of the outlook for the Gulf and also for EOR, just that whatever your base declines are now, any sort of catch-up capital maybe to maintenance or anything like that, but it sets you up flat in the Gulf and maybe flat to growing in the EOR over the next couple of years. Just what you did to get comfortable with that outlook?

Vicki Hollub: I think just starting to restore the capital to both of those assets have been helpful. And it is things that we never stopped doing was investing and making each of those operations better. And that’s why a little bit of the increase in OpEx is making in the EOR business getting some of the wells that had gone down during the pandemic, putting those wells back online, which increased our well maintenance budget. But those are very inexpensive and high-return barrels. So starting to do that. And we didn’t shut down any kind of maintenance around the infrastructure, no kind of decreases in capital around the maintenance of our equipment. So really, it was more from the standpoint of just getting wells back online for EOR.

And in the Gulf of Mexico, we’ve taken the opportunity to work on the — not only the surface to ensure that we could increase our run time there with reduced capital and not being as aggressive with drilling wells out there, we were still improving productivity by spending dollars on improving run time and also putting in subsurface pumping equipment to expand the radius of our spars and to also increase productivity and extend our reserve lives out there. So the work that we’ve done in the Gulf of Mexico has really kept us prepared to get back to sustaining levels, both in the Gulf and EOR, without any sort of issues beyond the next year or 2.

Roger Read : Okay. And just as a quick follow-up. Any issues with permitting anywhere on federal lands or in federal waters?

Vicki Hollub: I’m sorry, what was that? Permitting —

Roger Read : Yes, permitting since you’re not so much federal onshore, but federal offshore.

Vicki Hollub: Federal offshore, we’ve had — not had issues permitting thus far. Even when the permitting moratorium came out, we were able to still get things done and get things approved. And so I don’t see the permitting point to be an issue for us offshore at this point.

Operator: And our next question today comes from John Royall with JPMorgan.

John Royall : So just looking at your guidance for domestic OpEx per barrel in 2023. It looks like it’s up about 6.5% from last year. And more in line with the 2H of ’22, which I think Rob said in the prepared comments. Just comparing that with the 15% inflation on the capital side, can you talk about the gap there on why the OpEx inflation rate is so much better than the CapEx inflation rate?

Vicki Hollub: Yes. I’ll just reiterate the comments I made about the and then Richard’s got some information on onshore. But for the Gulf of Mexico, as I was saying, some of the work that we did was just to prove up our ability to increase our run time there. And that in and of itself is going to increase your OpEx a little bit this year and a little bit for next year, but it’s delivering in terms of barrels because, as you’ve seen, the Gulf of Mexico has helped to offset some of the declines from other areas and some of the storms. So we’re better prepared offshore now for higher productivity. Richard, do you have some on the permits?

Richard Jackson: Yes. Maybe just a little bit on onshore OpEx. I mean, one major difference when you look at capital on that 15% and then kind of what we’re seeing in OpEx is OCTG. While we have some exposure to that in our kind of maintenance activities, it’s far less pronounced, and that was the single biggest category really last year for us. So really, OpEx, it’s been a couple of things. We break it down into inflation and then scope and scope would be some of the maintenance activities like Vicki’s describing for the GoM so really 2022 from an OpEx perspective, U.S. onshore, most of it was really WTI or kind of price indexed inflation, things like power, CO2 price which were a little unique there, gas processing, things like that.

And really scope was pretty well managed. We — our maintenance activities picked up a bit at the end of the year, mainly downhole maintenance and EOR. As Vicki said, as you go into 2023, it’s much more balanced. If you see the increase, there is a little bit of kind of inflation carryover in terms of processing and CO2 volumes are up a bit this year for EOR as we’ve resumed activity there, but it’s a lot more scope. So as we begin to resume production activities, water management, compression, these type of things show up. But by and large, we’ve been able to hold that cost structure for OpEx pretty well. We go back really kind of first quarter ’20 and look at those type of run rates, and we’ve been very good holding our cost structure since that.

Probably the last thing I’d say kind of to the maintenance activity similar to the GoM, for us, in U.S. onshore, it’s a lot about uptime improvement. So continuing to work with a third-party gathering and processing companies and then within our fields to be able to be resilient through weather and just sort of manage this production in a good way. So adding that uptime adds significant value to the year. And so some of our OpEx-related activities have been focused there as well.

John Royall : Great. And then next one is just on the quarterly progression of production. And apologies if I missed something here, but I see that the midpoint of production guidance stays the same in 1Q versus the full year, but you do have the Permian ramping and you have the Al Hosn project starting later in the year. So what are some of the moving pieces there that are kind of pulling things the other way? And then how do you expect production to progress throughout the year?

Richard Jackson: Maybe I’ll start just kind of a U.S. onshore perspective. Permian being able to ramp up to the end of last year and really secure the resources by the end of the year puts us in a much better position for sort of steady-state growth. However, the first quarter, as we noted, is a little lumpy. We had about 40% less wells online versus kind of other quarters in the year or even against fourth quarter. It’s a little lumpy on the Permian — And then really the moving part is the Rockies. We’ve been underinvested from sustaining capital over the last several years. And so as we talked, resuming some activity there. We have about a fourth quarter ’22 to first quarter ’23 about 15,000 barrel a day decline and that sort of steadies out into the second quarter.

And then we actually start growing in the Rockies in the second half of the year. And so that, from an onshore perspective, is a big part of that moving part. And then the other one is really our GoM weather assumption. So I think that’s the other piece to consider when you look at the trajectory on total.

Vicki Hollub: Yes. In total, as Richard mentioned, GoM will be down a little bit, international up a little bit Al Hosn comes on and comes on stronger towards the end of the year.

Operator: And ladies and gentlemen, in the interest of time, this concludes our question-and-answer session. I’d like to turn the conference back over to Vicki Hollub for any closing remarks.

Vicki Hollub : Thank you. I’ll first by expressing my gratitude to our amazing teams for their diligent focus and pioneering work that contributed to so many advancements in our core cash generating and emerging Low Carbon businesses so much appreciate all that you do and for always going above and beyond. Thank you all to the rest of you for joining our call today for your questions. Have a good afternoon.

Operator: Thank you. This concludes today’s conference call. We thank you all for attending today’s presentation. You may now disconnect your lines, and have a wonderful day.