Occidental Petroleum Corporation

And welcome to Occidental's fourth quarter 2022 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touch-tone phone. To withdraw your question, please press star then two. Please note, today's event is being recorded. I would now like to turn the conference over to Neal Backhouse, Vice President of Investment Relations. Please go ahead.

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 Holla, 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 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. Reconciliation, so 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.

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, and our midstream business approximated guidance. Also in 2022, our high return Permian production grew by 90,000 DOE per day, propelled by outstanding well results. We delivered our best year ever in Delaware new well productivity, making 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 surface 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-to-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 is 172%, which increased our year-end 2022 reserves to approximately 3.8 billion BOEs. Except for the years of the price collapse in 2015 and 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-weld 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 in diverse industry sectors. We also secured over a 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 and gas approximated the midpoint of guidance, despite Winter Storm Elliott's impact. Outperformance from the Gulf of Mexico and Al-Hosin 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 NetPower. This is a technology that generates emission-free power generation 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 records set in 2022 were lateral links in the Delaware Basin, DJ Basin, Oman, and most notably in the Midland Basin where our well- Lulu 3641DP 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 two of our wells in the First Bone Springs in New Mexico and six 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 trades 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 two of our Gulf of Mexico assets, Horn Mountain and Cesar 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 eight 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 Alhosen with 85,500 BOE per day net to Oxy. The Alhosen expansion project is progressing well and remains on track for mid-2023 completion. We expect Oxy's Alhosen 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 dividends, 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 redemption of a portion of the preferred equity. Future cash and earnings growth opportunities could come from our shale and conventional oil and 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 chloralkali plant, and a new OxyChem plant enhancement, along with Permian EOR and 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 to $400 million. We expect the Battleground project to be online in early 2026. The other OxyChem plant enhancement will deliver higher production volumes, enhance operational efficiency, and improve 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 levels this year. In the Gulf of Mexico, infrastructure projects, including subsea pumping initiatives to increase the tieback radius and productivity of existing platforms, will drive high capital spending compared to recent years. We're also focused on our high-return short-cycle businesses, Our return to a two-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 and 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 and 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 and gas operations achieved zero routine flaring eight 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 force-based 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 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 require 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 OxyScope 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 Lake Charles 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 meet medium and long-term greenhouse gas emission reduction goals for Oxy and our customers. Before turning 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 retain 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.

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 our balance sheet and improving our credit metrics as we seek to regain investment-grade ratings. The completion of our $3 billion share purchase program moved us closer to returning over $4 per share to our common shareholders, which will begin to trigger redemption of the preferred equity. Our fastly improved financial position even compared to one 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 the redemption mechanics in a scenario where the $4 trigger is met. A mandatory redemption of preferred equity is triggered when the rolling 12-month common shareholder distributions reach a cumulative of $4 per share. This trigger is evaluated daily based on shares outstanding on the day capital is returned. As of today, we have distributed $3.78 per share, so an additional 22 cents 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 of trigger is reached. In conjunction with a common distribution, a $100 million mandatory matching distribution to Berkshire Hathaway will be made of which $91 million would 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 per share trailing 12-month distribution of common shareholders is greater than $4. There is no limit to exceeding the $4 per share trigger to additional distributions to common shareholders. Consequently, even if the trailing 12-month distribution declines, additional distribution of common shareholder will still trigger partial preferred equity redemption. We expect our refreshed shareholder purchase 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 the resulting enterprise value rebalancing will ultimately be driven by commodity prices, we expect our shareholders to benefit in a similar way to the value created in 2022 through debt reductions. 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. The difference between adjusted and reported profit was largely driven by a non-cash tax benefit related to the organization of legal entities. As Vicki mentioned, our board recently authorized a renewed $3 billion share purchase program on 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 repaying $1.1 billion of debt and retiring $450 million of notional interest rate swaps. For the year, we completed over $10.5 billion of debt repayments, which eliminated 37% of outstanding principal and resulted in a sizable reduction in interest burden. We estimate that the balance sheet improvements executed 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 so that 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 preferreds. 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 increase 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, schedule changes leading to activity in higher working interest areas, and rig startups for our Delaware JV. We further improved our liquidity position this month when ICP became the first company ever to securitize offshore oil and gas receivables in an amendment that increased 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 estimates. As we move into 2023, we expect to be a full U.S. federal cash taxpayer as we've utilized all rental wells and U.S. general business carry forward credits. We expect our full year production to average 1.18 million BUA per day in 2023. As was the case last year, production in the first quarter is expected to be lower than the preceding quarter due to scheduled maintenance and turnarounds primarily in our international operations. We'll have fewer wells come online in our U.S. onshore business in the first 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 two rigs in the DJ by the end of 2022. Given the reduced activity levels over the last few years, our Rocky's production is likely to be lower in 2023 than last year. Production is expected to stabilize in the second half of 2023 once the benefits from the additional rigs picked up in the fourth quarter of last year fully materialize. Step-back 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 plates. 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 DGA 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 BW per day, which is reflected in our 2023 guidance. We do not expect a material change in operating cash flows, because the tax rate were also reset under the new PSC. Operating costs across our oil and gas business are expected to approximate the second half of 2022, as inflationary pressures remain and our lower-cost DJ base and production declines. In the Gulf of Mexico, maintenance work to further reduce planned downtime and extend platform lives will impact operating costs. We are also increasing EOR downhaul maintenance work and CO2 purchases. On a BOE basis, operating costs may increase internationally, due to lower reported barrels from 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, though it is unlikely to match 2022. OxyChem prices reached all-time highs in the fourth quarter of 2022, but we are now facing downward pricing pressures as the macroeconomic environment remains uncertain. PUC pricing fell sharply in the second half of 2022, but has begun to stabilize. As I've mentioned before, OxyGyn'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 show return framework. I will now turn the call back over to Vicki.

We're now ready to take your questions.

Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your touch-tone phone. If you are using a speaker phone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. Please limit questions to one primary question and one follow-up. If you have further questions, you may re-enter the question queue. At this time, we will pause momentarily to assemble our roster. And today's first question comes from Raphael Dubois with Associated General.

Please go ahead.

Hello. Thank you very much for taking my questions. 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 means that other DACs, the ones that follow, could also be delayed. That would be my first question, please.

No, we don't expect delays in the other DACs. The delay came because of the supply chain 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.

Great. Thank you very much. And my follow-up is on the $200 to $600 million CapEx for the low carbon. Can you maybe help us better understand what is dedicated for that one and what is left for other projects?

We haven't broken out that $200 to $600 million at this point. Okay, Richard, do you have anything?

Yeah, 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 years with our construction pace. We do continue to develop our CCUS hubs around the Gulf Coast that we 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 will be able to keep us on pace for that development as well.

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

Please go ahead. Morning, Vicki. Thanks for taking my questions this afternoon.

Thank you.

I wanted to dig in a little bit more. You talked a bit about reaching this $4 per share return of 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-month $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?

You know, 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 toward 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 proposition. 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 if 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.

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 timeline for 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?

Hey, David, this is Richard. I'll try to answer a piece of that. You know, really two pieces, as you described, and we continue to have good discussions with capital partners, not only for DAC1, 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, you know, 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 you know, 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, is just a unique opportunity to look at sort of the large-scale build-out when we've contemplated the 30 DACs for that area. 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.

Thank you. And our next question today comes from Janine Way with Barclays. Please go ahead.

Hi, good afternoon. Thanks for taking our questions. Good afternoon. Hi, Vicki. Our two questions, I guess, are on the Permian, if we could. The first one may be 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 and assumptions between the old and the new inventory calculations, whether It's on costs or on development strategy. For example, we saw in the footnote there that your updated inventory uses a 22 budgeted well cost. And, you know, how different would that look if you used current costs?

Great. Hey, Janine, this is Richard. I'll try to help answer a few of those. I mean, very proud of our inventory. You know, 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. 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 you know, develop some new areas in zones. So, for example, the first bone spring wells that we noted, very proud of those. What happened during that, you know, underinvestment 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 development 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 drilled 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 But even in areas like the Powder River Basin, we're resuming some activity this year.

Okay, great. Thank you for that detail. 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's got a ton of different operating areas, and there's a lot of different ways to keep production flat there. Thank you.

Yeah, 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 on a multi-year basis. 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 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 EOR 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 Alhosen, which will not buy 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, at least initially, is very complementary. So we have the best of all worlds, I think, in the diverse portfolio that we have.

Thank you. And our next question today comes from Matt Portillo with TPH. Please go ahead.

Good morning, all. Good morning. 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 point source 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.

Okay, thank you for the question. I'll pass that to Richard.

Yeah, great. Hey, Matt. You know, 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 and 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 put together. So we have really five hubs that we're working that we've talked about. We've got several classics wells in progress as well as characterization of these sites. The midstream providers are very important. you know, 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 years, you know, we're hopeful that as we go this year, more projects will be able to combine that capture to transport to sequestration and really hit FID and then, you know, begin construction over the next couple of years. I think, you know, 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. You know, that really puts us in a good position to take together the synergies with DAC as we develop that. And so... You know, we're playing that role and having good conversations towards those projects. And again, expect this year to have more updates.

Great. And then as my follow-up, just around OxyChem, a strong start to the year with the Q1 guide. I'm just curious how you all are feeling about the outlook for Caustic and PBC and maybe what's baked into the guidance expectations as we progress through 2023.

Yeah, sure, Matt. So what we ended up seeing for the year was domestic PBC demand was actually down about 6.8% in 22 relative to 21. What we did was we saw in the industry that export demand ended up being about 46% higher. So the total PBC demand actually grew about almost 7% year over year in 22. And so we're looking into what's going on and what's in our guidance. We saw that softness in PBC through the fourth quarter. But it appears that bottomed out late 2022, early 2023. So all PBC buyer adjustments, we believe, were largely completed as prices were falling. And we believe, as we sit here today, that many buyers' inventories are low as we enter the construction season. We've also seen PBC export prices not only bottom, but are actually starting to trend upward most recently. And in the domestic market, all the producers have independently announced price increases in the domestic market for PVC. So thinking about the guidance in PVC, it reflects the uncertainty on 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 PBC business, globally impacting trade flows for PBC. So that's what's factored into this kind of murky outlook for PBC. The caustic soda business, we saw export prices. I discussed my early comments in the export bar decline, not just from the impact of the global economy from the China taking, again, longer to restart, but also the European markets stocked up significantly on caustic soda as we went into winter. That certainly has started to loosen now. They've gone from tight market conditions to looser market conditions. And these operating costs come down dramatically in Europe as energy prices have fallen. Our guidance on the cost 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. 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 that we're going to know a lot more about the total trajectory of the year than we do 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.

Thank you. And our next question today comes from Doug Leggett with Bank of America. Please go ahead.

Hey, guys. 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. Vicky, 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 Anadarko 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 optics. Can you give us your latest thoughts on what you see as the trajectory longer term for the Gulf?

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 have the development ready to continue 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.

for what period?

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 somewhere between five and ten years of potential inventory to maintain what we have today.

That's helpful. Thank you. My follow-up is a favorite question of mine, though I hate to be predictable, but I want to ask about your break-even, but nuance it a little bit. Obviously, we've had some inflation. Your break-even capital, what do you reckon that is today? And I guess what I'm really trying to understand is how you think about dividend capacity as part of that break-even. You know, let's say it's 40 bucks. Has that become like a ceiling for your dividend thoughts? And I guess the clarification point, if I may, Vicky, is that there's been a lot of questions today about DAC, obviously. When you think about that break-even, are you including the capital or sustaining capital for the DAC business as well? Thank you.

Well, certainly I would say that we are not including the capital for the DAC as a part of our break-even 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 break-even for us, and I kind of wish we had never brought that term up because it's so misleading to people. I would say the difference in where we are today and where maybe we've been in prior times is that we keep a model of what it... what it's going to take to support our dividend at various oil price levels. And what we 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, it's what would the price and the world look like at $40. 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 what it would be, what the calculation would show the break-even is today. So break-even 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 an OPEX and even labor costs, 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. 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 resource 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.

Thank you. And our next question today comes from Paul Chang at Scotiabank. Please go ahead.

Thank you. Good afternoon. Two questions, please. I have to apologize. I want to go back into the inventory. That number, how that will change for those that is for less than $50 WTI and if we change the Henry Hub gas pie to $2.50 and the internal weight will return to, say, 15%, 20%. and also fully 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, or at least some of them, have signed the LNG supply agreement, and one of your largest peers actually made an equity investment in the LNG plan. I want to see if Oxy thinks that that would be a suitable investment for you. and what is the game plan there? Thank you.

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, you know, our core competence is getting the most out of oil and 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 and gas development and our low-carbon business, 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.

Hi, Paul. This is Richard. 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, you know, plus 50% type program returns and even at a lower gas price, you know, than what we show there. So, you know, it will impact things, but I think in terms of the strong returns that we have, well exceed sort of our expectations on return on capital. And, you know, we continue to manage that inventory to drive really what we develop into those lower break-even categories. Probably the other thing to To say on that, you know, basically the inventory this year with the wells that we drill are all less than $40 break-even. So we've been able to high-grade ahead of time to make sure that we have sustainability of those returns. As I mentioned earlier, the wells that we've targeted to replenish 100% of our drilled wells this year will expect to carry that same result.

Thank you. And our next question today comes from Roger Reed with Wells Fargo.

Please go ahead.

Yeah, thanks. Good afternoon.

I'd like to follow up really, I guess, on the Gulf of Mexico, maybe secondarily on the EOR side, you know, 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 You know, whatever your base declines are now, any sort of catch-up capital, maybe to maintenance or anything like that, but that sets you up for, you know, 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.

I think just starting to restore the capital to both of those assets has been helpful, and it is basically all that we needed to do. One of the things that we never stopped doing was investing in 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 and 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 not only the surface to ensure that we could increase our runtime there with reduced capital and not being as aggressive with drilling wells out there. We were still improving productivity by spending dollars on improving runtime. and also putting in subsurface pumping equipment to expand the radius of our spars and to also increase productivity and extend our reserve life 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 two.

Okay, thanks. And just as a quick follow-up, any issues with permitting anywhere on federal lands or in federal waters? I'm sorry, what was that? Permitting. Yeah, permitting, since you're in not so much federal onshore, but federal offshore.

Federal offshore, we've 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 that permitting is going to be an issue for us offshore at this point.

Thank you. And our next question today comes from John Royale with JP Morgan. Please go ahead.

Hey, guys. Good afternoon. Thanks for taking my question. So just looking at your guidance for domestic OPEX per barrel in 2023, Looks like it's up about 6.5% from last year and more in line with 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?

Yeah, I'll just reiterate the comments I made about the GOM, 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 effects 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 offset some of the declines from other areas and some of the storms. So we're better prepared offshore now for higher productivity. Richard, you have some on the permanent?

Yeah, maybe just a little bit on onshore OPEX. I mean, one major difference when you look at capital in 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, you know, 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 ruts, which were a little unique there, gas processing, things like that. And really, scope was pretty well managed. 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 in CO2. volumes are up a bit this year for EORs. 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 our third-party gathering and processing companies and then, you know, within our fields to be able to, you know, be resilient through weather. and just sort of manage this production in a good way. So, you know, adding that uptime adds significant value to the year. And so some of our OPEX-related activities have been focused there as well.

Great. Thank you. And then the next one's just on the quarterly progression of production. And apologies if I've missed something here, but I see that the midpoint of production guidance stays the same in one queue versus the full year. But you do have the Permian ramping and you have the Alhosen project starting later in the year. So what are some of the moving pieces there that are kind of pointing things the other way? And then how do you expect production to progress throughout the year?

Maybe I'll start just kind of a U.S. onshore perspective. You know, Permian, you know, 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. The first quarter, as we noted, is a little lumpy. We had about, the way I had it, about 40% less wells on line 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 talk, resuming some activity there. We have about a... fourth quarter 22 to first quarter 23, about a 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 weather.

Yeah, I'm total. As Richard mentioned, Dom will be down a little bit, international up a little bit as Al Hoosen comes on and comes on stronger toward the end of the year.

Thank you. 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 Holland for any closing remarks.

Thank you. I'll close 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. So thank you all to the rest of you for joining our call today and for your questions. Have a good afternoon.

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. you Thank you. Thank you.

Bye.

Good afternoon and welcome to Occidental's fourth quarter 2022 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touch-tone phone. To withdraw your question, please press star then two. Please note, today's event is being recorded. I would now like to turn the conference over to Neal Backhouse, Vice President of Investment Relations. Please go ahead.

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 Hollup, 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 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 to our earnings release and on our website. I'll now turn the call over to Vicki. Vicki, please go ahead.

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, and our midstream business approximated guidance. Also in 2022, our high return Permian production grew by 90,000 DOE per day, propelled by outstanding mail results. We delivered our best year ever in Delaware new well productivity, making 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-to-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 is 172%, which increased our year-end 2022 reserves to approximately 3.8 billion BOEs. Except for the years of the price collapse in 2015 and 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-weld 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 in diverse industry sectors. We also secured over a 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 and gas approximated the midpoint of guidance, despite Winter Storm Elliott's impact. Outperformance from the Gulf of Mexico and Al-Hosin 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 NetPower. This is a technology that generates emission-free power generation It 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 records set in 2022 were lateral links in the Delaware Basin, D.J. Basin, Oman, and most notably in the Midland Basin where our wells Lulu 3641DP 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 two of our wells in the First Bone Springs in New Mexico and six 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 trades 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 two of our Gulf of Mexico assets, Horn Mountain and Cesar 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 eight 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 Alhosen with 85,500 BOE per day net to Oxy. The Alhosen expansion project is progressing well and remains on track for mid-2023 completion. We expect Oxy's Alhosen 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 dividends, 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 redemption of a portion of the preferred equity. Future cash and earnings growth opportunities could come from our shale and conventional oil and 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 chloralkali plant, and a new OxyChem plant enhancement, along with Permian EOR and 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 to $400 million. We expect the Battleground project to be online in early 2026. The other OxyChem plant enhancement will deliver higher production volumes, enhance operational efficiency, and improve 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 levels this year. In the Gulf of Mexico, infrastructure projects, including subsea pumping initiatives to increase the tieback radius and productivity of existing platforms, will drive high capital spending compared to recent years. We're also focused on our high-return short-cycle businesses, Our return to a two-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 and 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 and 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 and gas operations achieved zero routine flaring eight 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 force-based 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 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 require 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 OxyScope 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 Lake Charles 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 meet medium and long-term greenhouse gas emission reduction goals for Oxy and our customers. Before turning 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 retain 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.

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 our balance sheet and improving our credit metrics as we seek to regain investment-grade ratings. The completion of our $3 billion share purchase program moved us closer to returning over $4 per share to our common shareholders, which will begin to trigger redemption of the preferred equity. Our fast and improved financial position even compared to one 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 the redemption mechanics in a scenario where the $4 trigger is met. A mandatory redemption of preferred equity is triggered when the rolling 12-month common shareholder distributions reach a cumulative of $4 per share. This trigger is evaluated daily based on shares outstanding on the day capital is returned. As of today, we have distributed $3.78 per share, so an additional 22 cents 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 of trigger is reached. In conjunction with a common distribution, a $100 million mandatory matching distribution, Berkshire Hathaway will be made of which $91 million would 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 per share trailing 12-month distribution of common shareholders is greater than $4. There is no limit to exceeding the $4 per share trigger to additional distributions to common shareholders. Consequently, even if the trailing 12-month distribution declines, additional distribution of common shareholder will still trigger partial preferred equity redemption. We expect our refreshed shareholder purchase 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 the resulting enterprise value rebalancing will ultimately be driven by commodity prices, we expect our shareholders to benefit in a similar way to the value created in 2022 through debt reductions. 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. The difference between adjusted and reported profit was largely driven by a non-cash tax benefit related to the organization of legal entities. As Vicki mentioned, our board recently authorized a renewed $3 billion share purchase 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 court with approximately $1 billion of unrestricted cash after repaying $1.1 billion of debt and retiring $450 million of notional interest rate swaps. For the year, we completed over $10.5 billion of debt repayments, which eliminated 37% of outstanding principal and resulted in a sizable reduction in interest burden. We estimate that the balance sheet improvements executed 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 so that 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 preferreds. 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 increase 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, schedule changes leading to activity in higher working interest areas, and rig startups for our Delaware JV. We further improved our liquidity position this month when ITB became the first company ever to securitize offshore oil and gas receivables in an amendment that increased 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 estimates. As we move into 2023, we expect to be a full U.S. federal cash taxpayer as we've utilized all rental wells and U.S. general business carry-forward credits. We expect our full-year production to average 1.18 million BUA per day in 2023. As was the case last year, production in the first quarter is expected to be lower than the preceding quarter due to scheduled maintenance and turnarounds primarily in our international operations. We'll have fewer wells come online in our U.S. onshore business in the first 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 two rates in the DGA by the end of 2022. Given the reduced activity levels over the last few years, our Rocky's production is likely to be lower in 2023 than last year. Production is expected to stabilize in the second half of 2023 once the benefits from the additional rigs picked up in the fourth quarter of last year fully materialize. Step-back 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 plates. 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 DGA 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 BW per day, which is reflected in our 2023 guidance. We do not expect a material change in operating cash flows, because the tax rate were also reset under the new PSC. Operating costs across our oil and gas business are expected to approximate the second half of 2022, as inflationary pressures remain and our lower-cost DJ base and production declines. In the Gulf of Mexico, maintenance work to further reduce planned downtime and extend platform lives will impact operating costs. We are also increasing EOR down-haul maintenance work and CO2 purchases. On a BOE basis, operating costs may increase internationally, due to lower reported barrels from 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, though it is unlikely to match 2022. OxyChem prices reached all-time highs in the fourth quarter of 2022, but we are now facing downward pricing pressures as the macroeconomic environment remains uncertain. PUC pricing fell sharply in the second half of 2022, but has begun to stabilize. As I've mentioned before, OxyGyn'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 show return framework. I will now turn the call back over to Vicki.

We're now ready to take your questions.

Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your touch-tone phone. If you are using a speaker phone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. Please limit questions to one primary question and one follow-up. If you have further questions, you may re-enter the question queue. At this time, we will pause momentarily to assemble our roster. And today's first question comes from Raphael Dubois with Associated General. Please go ahead.

Hello. Thank you very much for taking my questions. 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 means that other DACs, the ones that follow, could also be delayed. That would be my first question, please.

No, we don't expect delays in the other DACs. The delay came because of the supply chain 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.

Great. Thank you very much. And my follow-up is on the $200 to $600 million CapEx for the low carbon. Can you maybe help us better understand what is dedicated for that one and what is left for other projects?

We haven't broken out that $200 to $600 million at this point. Okay, Richard, do you have anything?

Yeah, 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 years with our construction pace. We do continue to develop our CCUS hubs around the Gulf Coast that we previously disclosed and we announced with the Midstream Partnership today. And then, you know, 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 will, you know, be able to keep us on pace for that development as well.

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

Please go ahead. Morning, Vicki. Thanks for taking my questions this afternoon.

Thank you.

I wanted to dig in a little bit more. You talked a bit about reaching this $4 per share return of 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-month $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?

You know, 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 toward 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 proposition. 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 if 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.

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 timeline for 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?

Hey, David, this is Richard. I'll try to answer a piece of that. You know, really two pieces, as you described, and we continue to have good discussions with capital partners, not only for DAC1, 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 you know, 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, is just a unique opportunity to look at sort of the large-scale build-out when we've contemplated the 30 DACs for that area. 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.

Thank you. And our next question today comes from Janine Way with Barclays.

Please go ahead.

Hi, good afternoon. Thanks for taking our questions. Good afternoon. Hi, Vicki. Our two questions, I guess, are on the Permian, if we could. The first one may be 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 and assumptions between the old and the new inventory calculations, whether It's on costs or on development strategy. For example, we saw in the footnote there that your updated inventory uses a 22 budgeted well cost. And, you know, how different would that look if you used current costs?

Great. Hey, Janine, this is Richard. I'll try to help answer a few of those. I mean, very proud of our inventory. You know, 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 you know, develop some new areas and zones. So, for example, the first bone spring wells that we noted, very proud of those. What happened during that, you know, underinvestment 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 development 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 drilled 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 But even in areas like the Powder River Basin, we're resuming some activity this year.

Okay, great. Thank you for that detail. 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's got a ton of different operating areas, and there's a lot of different ways to keep production flat there. Thank you.

Yeah, 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 on a multi-year basis. 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 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 EOR 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 Alhosen, which will not buy 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, at least initially, is very complementary. So we have the best of all worlds, I think, in the diverse portfolio that we have.

Thank you. And our next question today comes from Matt Portillo with TPH. Please go ahead.

Good morning, all. Good morning. 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 point source 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.

Okay, thank you for the question. I'll pass that to Richard.

Yeah, great. Hey, Matt. You know, 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, it's sort of similar to oil and 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 put together. really five hubs that we're working that we've talked about. We've got several classics 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 years, we're hopeful that As we go this year, more projects will be able to combine that capture to transport to 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 how do you manage that kind of across the value chain? And so our focus is, again, really on that sequestration. You know, that really puts us in a good position to take together the synergies with DAC as we develop that. And so, you know, we're playing that role and having good conversations towards those projects. And, again, expect this year to have more updates.

Great. And then as my follow-up, just around OxyChem, a strong start to the year with the Q1 guide. I'm just curious how you all are feeling about the outlook for Caustic and PBC and maybe what's baked into the guidance expectations as we progress through 2023.

Yeah, sure, Matt. You know, so what we ended up seeing for the year was domestic PBC demand was actually down about 6.8% in 2022 relative to 2021. What we did was we saw in the industry that export demand ended up being about 46% higher. So the total PBC demand actually grew about almost 7% year over year in 22. And so we're looking into what's going on and what's in our guidance. We saw that softness in PBC through the fourth quarter, but it appears that bottomed out late 2022, early 2023. So all PBC buyer adjustments, we believe, were largely completed as prices were falling. And we believe, as we sit here today, that many buyers' inventories are low as we enter the construction season. We've also seen PVC export prices not only bottom, but are actually starting to trend upward most recently. And in the domestic market, all the producers have independently announced price increases in the domestic market for PVC. So thinking about the guidance in PVC, it reflects the uncertainty or 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 PBC business, globally impacting trade flows for PBC. So that's That's what's factored into this kind of murky outlook for PBC. The caustic soda business, we saw export prices, I discussed in my early comments, an export bar decline, not just from the impact of the global economy from the China taking, again, longer to restart, but also the European markets stocked up significantly on caustic soda as we went into winter. That certainly has started to loosen now, so you've gone from tight market conditions to looser market conditions, and these 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. But again, I would say, as we've talked in the past, our chemical business is so heavily 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 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. Overall, that guidance for the year just reflects that uncertainty around both sides of the business at this point.

Thank you. Our next question today comes from Doug Leggett with Bank of America. Please go ahead.

Hey, guys. 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. Vicky, I want to ask you 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 Anadarko 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 optics. Can you give us your latest thoughts on what you see as the trajectory longer term for the Gulf?

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 have the development ready 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.

For what period?

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

That's helpful. Thank you. My follow-up is a favorite question of mine, though I hate to be predictable, but I want to ask about your breakeven, but nuance it a little bit. Obviously, we've had some inflation. Your breakeven capital, what do you reckon that is today And I guess what I'm really trying to understand is how you think about dividend capacity as part of that breakeven. You know, let's say it's 40 bucks. Is that become like a ceiling for your dividend thoughts? And I guess the clarification point, if I may, Vicky, is that 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? Thank you.

Well, certainly I would say that we are not including the capital for the DACs as a part of our break-even 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 to break even for us, and I kind of wish we had never brought that term up because it's so misleading to people. I would say the difference in where we are today and 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, it's 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 break-even is today. So break-even 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 an OPEX and even labor costs, 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. 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 resource 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 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.

Thank you. And our next question today comes from Paul Chang at Scotiabank. Please go ahead.

Thank you. Good afternoon. Two questions, please. I have to apologize. I want to go back into the inventory. That number, how that will change for those that is for less than $50 WTI and if we change the Henry Hub gas pie to $250 and the internal weight will return to, say, 15%, 20% and also fully 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, or at least some of them, have signed the LNG supply agreement, and one of your largest peers actually made an equity investment in the LNG plan. I want to see if Oxy thinks that that would be a suitable investment for you, and what is the game plan there? Thank you.

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 and 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 and gas development and our low-carbon business, 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.

Hi, Paul. This is Richard. I'll try to answer your question on the inventory. I mean, as you think about 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. You know, it will impact things, but I think in terms of the strong returns that we have, well exceed sort of our expectations on return on capital. And, you know, we continue to manage that inventory to drive really what we develop into those lower break-even categories. Probably the other thing to say on that, you know, basically the inventory this year with the wells that we drill are all less than $40 break-even. 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 will expect to carry that same result.

Thank you. And our next question today comes from Roger Reed with Wells Fargo.

Please go ahead.

Yeah, thanks. Good afternoon.

I'd like to follow up. Really, I guess on the Gulf and Mexico, maybe secondarily on the EOR side, you know, 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, you know, whatever your base declines are now, any sort of catch-up capital maybe to, maintenance or anything like that, but that sets you up for, you know, 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.

I think just starting to restore the capital to both of those assets has been helpful, and it is basically all that we needed to do. One of the things that we never stopped doing was investing in 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 and no kind of decreases in capital costs 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 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 life 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 two.

Okay, thanks. And just as a quick follow-up, any issues with permitting anywhere on federal lands or in federal waters?

I'm sorry, what was that? Permitting.

Yeah, permitting. Since you're in not so much federal onshore, but federal offshore.

Federal offshore, we've 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 that permitting is going to be an issue for us offshore at this point.

Thank you. And our next question today comes from John Royale with JP Morgan. Please go ahead.

Hey, guys. Good afternoon. Thanks for taking my question. So just looking at your guidance for domestic OPEX per barrel in 2023, Looks like it's up about 6.5% from last year and more in line with 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?

Yeah, I'll just reiterate the comments I made about the GOM, 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 effects 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 offset some of the declines from other areas and some of the storms. So we're better prepared offshore now for higher productivity. Richard, you have some on the permanent?

Yeah, maybe just a little bit on onshore OPEX. I mean, one major difference when you look at capital in 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, you know, 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. And 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 ruts, which were a little unique there, gas processing, things like that. And really, scope was pretty well managed. 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 in CO2. volumes are up a bit this year for EORs. 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 our 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, you know, adding that uptime adds significant value to the year. And so some of our OPEX-related activities have been focused there as well.

Great, thank you. And then the next one's just on the quarterly progression of production. And apologies if I've missed something here, but I see that the midpoint of production guidance stays the same in one queue versus the full year. But you do have the Permian ramping and you have the Alhosen project starting later in the year. So what are some of the moving pieces there that are kind of pointing things the other way? And then how do you expect production to progress throughout the year?

Maybe I'll start just kind of a U.S. onshore perspective. You know, Permian, you know, 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. The first quarter, as we noted, is a little lumpy. We had about, you know, the way I had it, about 40% less wells on line 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. You know, we've been underinvested from sustaining capital over the last several years. And so as we talk, we're resuming some activity there. We have about a... fourth quarter 22 to first quarter 23, about a 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 weather.

Yeah, I'm total. As Richard mentioned, Dom will be down a little bit, International up a little bit as Al Hoosen comes on and comes on stronger toward the end of the year.

Thank you. 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 Holland for any closing remarks.

Thank you. I'll close 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. So thank you all to the rest of you for joining our call today and for your questions. Have a good afternoon.

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.