Good afternoon, and welcome to Occidental's First Quarter 2023 Earnings Conference Call. Please note this event is being recorded. I would now like to turn the conference over to Neil Backhouse, Vice President of Investor Relations. Please go ahead.

Thank you, Jason. Good afternoon, everyone, and thank you for participating in Occidental's First Quarter 2023 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Robert Peterson, Senior Vice President and Chief Financial Officer; and Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management. This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on Slide 2 regarding forward-looking statements that will be made on the call this afternoon. We'll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules to our earnings release and on our website. I'll now turn the call over to Vicki. Vicki, please go ahead.

Thank you, Neil, and good afternoon, everyone. The operational and financial successes we achieved last year continued into 2023 as I will detail in our first quarter call. Our operational excellence and disciplined approach to capital spending enabled us to meaningfully progress our shareholder return framework. Our continued efforts to strengthen our balance sheet culminated in regaining an investment-grade credit rating from Moody's. This afternoon, I will begin by covering our first quarter performance, followed by an update on several accomplishments in our oil and gas business. In light of recent market volatility, I will then go over the cash flow priorities established during our last call and highlight the progress made in transferring enterprise value to our common shareholders. Then, Rob will detail the commencement and status of the preferred equity redemption before covering our financial results and guidance, including an increase to full-year oil and gas production and OxyChem pretax earnings. Our operational success even in the first quarter's lower commodity price environment enabled us to generate approximately $1.7 billion of free cash flow before working capital. Excess cash was primarily allocated towards approximately $750 million of common share repurchases in the quarter, accounting for over 25% of our $3 billion share repurchase program and triggering the redemption of nearly $650 million of preferred equity. Operationally, we exceeded our production guidance midpoint by approximately 40,000 BOE per day, following a prolific first quarter across our premier asset portfolio. In the Gulf of Mexico, we achieved our highest quarterly production in over a decade. This outperformance was partially driven by higher uptime in Horn Mountain and the outperformance following the successful Caesar-Tonga subsea system expansion project, which was completed in December. Our Permian production benefited from strong new well performance and higher operability primarily in the Texas Delaware. In the Rockies, strong base and new well performance and higher operated-by-other volumes in the DJ Basin resulted in higher-than-expected production. Internationally, our businesses performed well. Most notably, the Al Hosn gas expansion project is ahead of schedule because of the team's ability to integrate expansion work with annual turnarounds. The production ramp-up has commenced earlier than anticipated and has already led to a daily production record. These achievements demonstrate how our high-quality assets and talented teams provide the strongest foundation for free cash flow generation in Oxy's history. Our global oil and gas teams continue to perform exceptionally well in the first quarter, achieving several milestones and accomplishments. Domestically, in our onshore unconventional businesses, we delivered strong well performance and established new operational records in the Rockies and Permian. Our Rockies team drilled the industry's longest DJ Basin well ever at over 25,000 feet in just 8 days. This well also set a new lateral length record for Oxy at over 18,000 feet. In addition, we delivered a single well production record in the DJ Basin by utilizing a new well design. We plan to roll out this enhanced design as we further develop our inventory across the DJ Basin. In the Permian, our Delaware subsurface teams continued to optimize and unlock inventory, as demonstrated by success in the deeper Wolfcamp horizon, with a single well generating a 30-day initial production rate of 6,500 BOE per day and an Oxy record for this interval. Our Delaware completions team also achieved a continuous pumping time of approximately 28 hours on another set of wells, far exceeding our previous record of about 22.5 hours. We expect that increasing efficiencies such as faster completions pumping will contribute to lower costs and a faster time to market. Though certain products and services utilized in our operations will likely incur price increases this year compared to 2022, we are seeing some early signs of tempered inflation. Our teams are working towards partially offsetting inflation impacts through various operational efficiencies and supply chain competencies. For example, in the Delaware Basin, we've optimized frac designs to reduce assets and water utilization for an average savings of around $240,000 per well. Our Rockies team has successfully integrated artificial intelligence into our plunger lift program, helping to maximize base production and reduce operating costs. On a broader scale, our supply chain team is continuously pursuing opportunities to manage pricing across our business portfolio through partnerships that thoughtfully balance contractual flexibility with cost management. These capabilities are more important than ever in the current inflationary environment as we strive to continuously deliver value to our shareholders. With these points in mind, I will now review our 2023 cash flow priorities. As we discussed last quarter, our 2023 cash flow priorities incorporate a disciplined capital strategy largely agnostic to the short-term volatility exhibited in commodity prices this year. Our 2023 capital plan remains on track and focused on sustaining our high-quality portfolio of assets while securing our long-term cash flow resilience. We continuously monitor the macroeconomic landscape and intend to maintain our capital plan in the current environment. Should a sustained downturn in commodity prices occur, we possess the flexibility to rapidly reduce activity levels through our short-cycle, low-breakeven projects. We demonstrated our nimble approach during the last global downturn, and we are prepared to do so again should market conditions dictate. If oil prices follow an upward trajectory, we do not expect notable changes to our cash flow priorities, though the pace of our share repurchase program and the preferred equity redemption may be accelerated. We have previously spoken about how potential future production growth is expected to be in the low single digits. However, we have many opportunities to grow cash flow outside of production growth. We anticipate that the mid-cycle investments we are making this year will result in meaningful contributions to our future cash flow. For example, our new OxyChem projects are expected to contribute $300 million to $400 million in incremental annual EBITDA, with benefits expected to start in late 2023 and full project benefits expected in early 2026. Additionally, near-term investments in our low-carbon debentures businesses are expected to enable the commercialization of exciting decarbonization technologies with the potential to generate cash flow detached from oil and gas price volatility. We believe that the combination of our low cash flow breakeven, high-return assets and emerging low-carbon businesses uniquely position us at the forefront of our industry to create value for our shareholders. Value creation for our common shareholders governs our cash flow priorities. The allocation of excess cash toward debt reduction over the past 2 years was key in positioning us to initiate the next phase of our shareholder return framework. Our balance sheet improvement efforts reduced interest and financing costs, which contributed to an increase in our sustainable and growing dividend and the completion of last year's share repurchase program. Building on this success, we've already completed over 1/4 of our current share repurchase program, enabling us to trigger the redemption of approximately $650 million of preferred equity in the first quarter. As dictated by our 2023 cash flow priorities, we intend to continue allocating excess free cash flow towards share repurchases, which, in turn, may trigger additional preferred equity redemptions. We expect that these measures will be accretive to cash flow on a per-share basis. In combination, we believe that these actions will further our goal of continued enterprise value rebalancing for our common shareholders and serve as a catalyst for future common equity appreciation. I'll now turn the call over to Rob.

Thank you, Vicki, and good afternoon, everyone. I want to begin the day by highlighting our March credit rating upgrade and positive outlook for Moody's Investor Service. Gaining the Moody's investment-grade rating is a significant milestone that acknowledges Oxy's recent financial transformation. Continued redemption of preferred equity, combined with opportunistic debt reduction, points to a compelling deleveraging story that we hope will facilitate future upgrades. The execution of our cash flow priorities over the last several quarters enabled us to begin redeeming the preferred equity. We have redeemed or have given notice to redeem approximately $647 million of preferred equity so far this year at a cost of approximately $712 million, including a 10% premium payment of close to $65 million. To date, we have eliminated approximately $52 million of annual preferred dividend while also transferring enterprise value to our common shareholders. During last quarter's call, we reviewed how the mandatory redemption of preferred equity is triggered when rolling 12-month common shareholder distributions reached a cumulative $4 per share. The preferred stock agreement requires at least a 30-day notice for each redemption. By the end of this week, all $647 million of preferred equity triggered for redemption during the first quarter will be fully redeemed. As of May 9, we have distributed $4.57 per share to common shareholders over the rolling 12-month period. We intend to continue repurchasing common shares in part to remain above the $4 trigger per share for as long as we are able. We recognize that staying above the $4 trigger will become more challenging in the latter half of this year due to the timing and pace of our prior share repurchase program. Our ability to remain above the $4 trigger will be heavily influenced by commodity prices. But even if we fall below the trigger, we plan to continue repurchasing common shares so that the distribution required to surpass the trigger in future quarters is more evenly spread throughout the year. During a period where we may be below the $4 trigger, we may also seek to retire debt opportunistically, which would achieve a similar result of transferring enterprise value to common shareholders and further enhancing our credit profile. Turning now to our first quarter results. We posted an adjusted profit of $1.09 per diluted share and a reported profit of $1 per diluted share. The difference between our adjusted and reported profit for the quarter was primarily driven by the premium paid to redeem the preferred equity. We concluded the first quarter with nearly $1.2 billion of unrestricted cash but had not yet made payments to preferred equity holders as of March 31 due to the 30-day redemption notice requirement. However, the first quarter call on the preferred equity is reflected in our balance sheet as an accrued liability and will be captured in future cash flow statements as payments to the preferred equity holders are made. During the first quarter, we generated approximately $1.7 billion of free cash flow before working capital, which was accomplished despite a lower commodity price environment as compared to the prior quarter, lower domestic realizations as compared to WTI, lower sales and production due to the quarter-end timing of cargo lifting in Algeria. We experienced a modestly negative working capital change during the period, which is typical for the first quarter and was primarily driven by semiannual interest payments on our debt, annual property tax payments, and payments under compensation and pension plans. These items, which are largely classified as accounts payable and accrued liabilities, were partially offset by a net decrease in receivables, driven by lower commodity prices. We see the potential for working capital to partially reverse in the second quarter since many of these payments are made annually in the first quarter, but accrued throughout the year. As discussed in the last call, we expect to be a full U.S. federal cash taxpayer in 2023, which is reflected in our financials by the reduced deferred income tax provision in our cash flow statement compared to prior quarters. We are pleased to update our full-year guidance for oil and gas and OxyChem as a result of excellent first quarter performance in both businesses. Vicki reviewed many of the highlights in our oil and gas business that contributed to our production outperformance across our high-quality assets portfolio. These factors enabled us to surpass our first quarter guidance and some are expected to continue having a positive impact on production throughout the year. Specifically, the acceleration of the Al Hosn gas expansion project and new well performance in our domestic onshore businesses are expected to yield higher production than originally planned. These positive results provided us with the confidence to increase our full-year production guidance midpoint to 1.195 million BOE per day. Looking ahead, we anticipate that the second quarter production will be the lowest of the year, primarily driven by the timing of domestic onshore activity and optimization of our maintenance schedule to reduce planned downtime in the Gulf of Mexico. As discussed on our last call, we expected that the first quarter of 2023 will have the fewest wells come online in our U.S. onshore business all year. This proved to be the case as the Rockies and Permian unconventional businesses turned 6 and 53 wells to production, respectively, in the first quarter. In the second quarter, we expect to turn a significantly higher number of wells into production, the benefits of which will be fully realized in the second half of the year. Quarterly timing fluctuations in bringing wells online and the resulting production impact are typically driven by the optimization of resources and pad development timing. Internationally, we expect higher production in comparison to the prior first quarter as our annual scheduled turnarounds were completed and production at Al Hosn is ramping up. Increased international production will be slightly offset by the just finalized Algeria production sharing contract, which decreases reported production but is not expected to have a material impact on operating cash flow. We anticipate that our second quarter oil mix will reduce to approximately 52%. The lower oil production in the Gulf of Mexico and Algeria, compounded by increased gas production at Al Hosn. While our oil mix will be lower in the second quarter, we expect that it will rebound in the second half of the year and be more in line with our full-year guidance once maintenance in the Gulf of Mexico is complete. Maintenance work and the associated lower volumes in the second quarter will also contribute to a domestic price operating cost increase of $9.85 per BOE before receding on a BOE basis in the latter half of the year. In summary, our impressive first quarter production and activity plans for the remainder of the year provide us with the confidence to raise full-year production guidance despite anticipated reduced production levels in the second quarter. OxyChem approximated guidance in the first quarter. Due to the seasonality of customers' chlorovinyl inventory orders, we anticipate the first half of the year will reflect stronger results compared to the latter half of 2023. Despite macroeconomic uncertainty, margins for OxyChem's chlorovinyl products remain robust and lead us to expect another year of strong results, providing us with the confidence to raise OxyChem's 2023 pretax income guidance midpoint to $1.5 billion. Midstream and marketing generated pretax income of $35 million in the first quarter, falling within our guidance range. First quarter results were primarily impacted by the timing of crude oil sales as well as favorable gas margins due to transportation capacity; optimization in the marketing business. These items were partially offset by lower equity method investment income from WES. Capital spending in the quarter approximated $1.5 billion and close to 25% of our 2023 capital plan, which remains at $5.4 billion to $6.2 billion. We expect higher capital spending in the second quarter compared to the first due to development timing in Rockies and Permian and advancement of the OxyChem Battleground modernization and expansion project. We also anticipate that capital spending in the third and fourth quarters will be below the second quarter and in line with full-year guidance. Overall, the first quarter represents an excellent start to 2023. As we look ahead to the rest of the year, we are favorably positioned to execute on our cash flow priorities and advance our shareholder return framework. We aim to continue shifting our capital structure in favor of our common shareholders in the near and long-term. I will now turn the call back over to Vicki.

Thank you, Rob. We're now ready for your questions.

Our first question comes from Neal Dingmann from Truist Securities.

My question is it seems that you are experiencing impressive efficiencies in the Permian and other areas, while there is also a possibility of softness in OFS that we've been hearing about. I would like to know if you expect to benefit from both of these situations. Will you stick to your current plan, and would you consider using the cash flow savings for buybacks, or are you planning to pursue more growth?

No, any additional cash flow we generate from various sources would be directed towards share repurchases, and ideally, the redemption of the preferred as well.

Okay, great to hear. Secondly, it seems like your DJ activity is set to significantly increase after having fewer operations in the first quarter than anticipated. Could you provide some insights regarding well pads? I have two questions about the DJ. First, I believe you are fine with permitting, but I wanted to confirm that. Second, are there any changes to your pad size expectations or your completion strategies?

Yes. I'll pass this to Richard.

Neil, thanks for that. It was a really strong quarter, and the outlook for our Rockies team looks promising. They have made significant progress with their production performance, largely due to the excellent wells that came online at the end of last year. Additionally, they have continued to enhance their production system. One significant improvement has been the earlier implementation of gas lift in many wells, including some of the legacy ones, providing a boost to our production. We executed several of these in the first quarter, but we anticipate fewer in the second quarter, so the immediate benefit may not be as pronounced. On the new well performance front, we were pleased to report a peak 24-hour record for one of our wells, which reflects positively on our new well outcomes in the Rockies. We've also been successful in reducing the number of wells per section, similar to our approach in the Permian, going from 18 wells down to 12, and we've increased profit concentration by about 30%. The team has been focused on improving the efficiency of the frac process and the time to peak production, which is essential as we plan for the rest of the year. To summarize, we delivered six wells in the first quarter, on track with our plans, and anticipate producing 20 to 30 wells per quarter through the end of the year, supporting our overall delivery targets. As we mentioned on the last call, while we expected some decline in the first half due to previous underinvestment, we now expect to shift towards growth in the second half, and both halves are looking better than our initial projections. We're very pleased with our team's progress.

Our next question comes from Neil Mehta from Goldman Sachs.

The first question pertains to short-term aspects, while the second focuses on low carbon. In the recent quarter, it appeared that price realizations were somewhat weak, and this seemed to relate to turnarounds in refining. Could you provide more insight on this as it contributed to some variation from consensus?

Well, Neil, I think there were 3 key components of that. First of all, looking at the calendar month average roll in terms of the NYMEX price, we've seen the market switch really from backwardation to contango at the end of March, impacting realizations by about $1.50 per barrel. So starting there across the domestic portfolio. Following that, in terms of the Gulf of Mexico, it had an amazing quarter. But at the same time, there were refineries on the Gulf Coast that had turnarounds going on. And so moving from the fourth quarter to the first quarter, realizations dropped against WTI by about $3.50 per barrel. Additionally, there was an outage in the DJ Basin as well, a third-party outage, which caused realizations there to drop by about $1 a barrel. So with those components altogether, that really impacted oil realizations.

That's really helpful. Could you provide an update on the low-carbon business as you work towards DAC-1? What is the latest regarding its development? Additionally, what are your thoughts on the voluntary market and how it can help bring the project closer to funding?

I want to share that we recently held an official groundbreaking for our low-carbon venture, DAC-1, which is currently under construction in the Permian Basin. The work commenced at the end of the last quarter, and during the groundbreaking event, we officially named the project Stratos. Progress is going very well, and we are genuinely excited about the direction the teams are taking with it. Would you like to discuss the carbon market?

Yes, sure. To provide some updates on our low-carbon progress, as Vicki mentioned, we are advancing with DAC-1 in the Permian and continuing our work on sequestration hubs in the Gulf Coast. We've submitted two more Class 6 wells in our hubs there, along with two additional wells to support our Permian operations. In the King Ranch area, we are planning to drill three stratigraphic test wells in preparation for the Class 6 submissions. We are focused on the preliminary work needed for development in both regions, addressing point source and DAC projects. Regarding the market, we observe that the voluntary market for our carbon dioxide removal sales remains strong and is growing. We expect to provide updates in the coming months as we approach significant developments. Additionally, the compliance market, particularly related to heavy-duty transportation and sustainable aviation fuels, is taking shape globally. We are seeing policies emerge that support carbon removals, similar to initiatives in the U.S. with the Inflation Reduction Act. The voluntary market is currently leading this effort, and we appreciate our strong partners who recognize the importance of carbon removals and the growth of compliance markets. They are actively helping us advance this technology and reduce costs while addressing long-term compliance market needs. We plan to share more updates later this year as we make progress, and we are confident that our revenue expectations for our DAC projects are on track.

Our next question comes from Doug Leggate from Bank of America.

I have a couple of follow-up questions because I noticed the reaction of your share price to the earnings last night, and the market seemed to have concerns. It seems that many analysts covering your company may not have experience with Anadarko and might not recall the seasonal factors affecting maintenance in the Gulf of Mexico. Could you take a moment to explain how you are managing that aspect of your business in relation to production seasonality?

Thank you, Doug, for mentioning that. You're correct; this aspect isn't very well understood. I want to clarify our forecast for the Gulf of Mexico. This situation is pretty typical. However, this year is different because we had an exceptionally strong first quarter. The impressive performance in Q1 can be attributed to our lowest downtime in quite some time, thanks to the teams' excellent operating performance. Additionally, we saw the Caesar-Tonga subsea system come online, contributing a gross increase of 15,000 barrels per day. Our Q1 results were bolstered by this strong performance, reduced downtime, and the postponement of Horn Mountain maintenance from Q1 to Q2 due to supply chain issues regarding material procurement. If we had performed the maintenance as originally scheduled, our results would look more like those of previous years. I believe the concern arises from the drop from 171 to a lower figure in Q2. However, Horn Mountain is one of our largest offshore producers, so maintenance in a specific quarter significantly impacts our numbers. We also have a few more maintenance projects lined up, as well as well work planned. Overall, the full-year outlook remains positive at 144,000 barrels a day, which hasn't changed. It's just the timing that appears more uneven than what people are accustomed to, primarily due to the larger maintenance that was deferred to Q2 along with higher production levels. Thank you for your question.

I appreciate the clarification, Vicki, as it’s noteworthy that this seems to be the primary focus of discussions after last night's results. I just wanted to remind everyone that the legacy Anadarko situation was completely normal. Thank you for the clarification. My follow-up is really a question for Rob. You mentioned inflation, or at least I think Vicki did in her comments, suggesting that things might be stabilizing a bit. However, your CapEx guidance remains quite broad. Could you provide some insight into the trend? Should we start considering the possibility of coming in towards the lower end of that range, or is it more activity-driven? Or have you already accounted for a reasonable amount of inflation that may not occur now?

I think as a discussion in Vicki's comments, and I heard also from Richard, is that we are seeing things sort of plateauing at this point. Some pieces are rolling over. There's still a fair amount of wage inflation pressures in the Permian that we are still seeing. So I wouldn't say we're ready to commit to the fact that things are going to roll over and decline for the balance of the year so we've maintained that guidance. As Vicki commented on the earlier question that if we are fortunate enough to have things fall off, and it allows us to continue the same level of activity for a lower cost, we would roll that back into additional share repurchases in the balance of the year. And then Richard probably has some additional comments.

Yes, that's perfect, Rob. I just wanted to add one more thing. Another factor we consider is the ongoing improvement in efficiency. Doug is ramping up from last year and starting this year, and we expect our rigs and frac cores to hit a steady state. We do anticipate continued efficiencies. While we highlighted the record performance of individual wells, we're looking forward to overall improvements in the second half of the year. This gives us a bit of leeway as the burn rate increases with the gains in efficiency.

Our next question comes from John Royall from JPMorgan.

So my first question is on chemicals. You were in line in 1Q, but you raised your full-year guide. So you're seeing something that's giving you more confidence in the remainder of the year, but it does feel like there should still be some challenges to the housing market. So just looking for some color on the guidance raised in chems so early in the year and what appears to be an uncertain environment?

Yes, John, I think you've characterized it actually pretty well in your question. So if you look at domestic PVC demand through the first quarter compared to last year, it's down about 18% year-over-year. However, what we've seen is the export business has picked up that slack in the first quarter as it's up almost 80% year-over-year. So we end up with a combined demand for PVC that's up about 2.5%, 2.7% for the country versus last year. And that driving on that softness in domestic demand, as we discussed on prior calls, is really being driven by housing construction sector. We still believe that inventories remain low for many PVC buyers as we're entering sort of the heart of construction season. But no doubt, there's encouraging macro conditions between inflation, mortgage rates, and regional bank issues have converters a little more reluctant to build what would be typical inventories for this time of the year for construction. So our guidance reflects that continued uncertainty and the trajectory of the global business and the domestic business. We still firmly believe there's a lot of pent-up demand for construction, but they're just cautious with the macro conditions. I would say, however, that the lower energy prices in terms of gas prices resulting in lower ethylene prices also create the opportunity for some margin in the business that might still be present and stickier even at these lower demand levels. That's part of the raise. I would say on the caustic side of the business, we're seeing this sort of balanced along type conditions. General manufacturing is certainly off from prior year, particularly automotive remains subdued. So domestic demand is similar to last year, but availability is certainly higher than it was before. And so we're seeing that result in some price erosion continually in the caustic side of the business. So we're still assuming that the unwinding of inventories in Europe takes the balance into the middle of the year and then the Chinese economy continues to open slowly. If either one of those happen more rapidly, that would certainly be favorable to the business. So that increase in guidance really reflects some optimism around things kind of reaching a stability point at least next quarter or so and then preserving some of the margins with the lower feedstock costs.

Great. And then my next question is on the paydown of the preferred. You gave some color on the downside case and if you end up going below $4 a share LTM. Is there a commodity price where you think you might expect to pull back on the buyback and go below that $4 a share? And just assuming we stay above it, is that $700 million-ish run rate, including the premium, a good go-forward click to think about?

I would say it's just based on the available cash. We'll use the free cash we have to continue buying shares and triggering the preferred when possible. We're monitoring this and have an outlook on it, so we're being thoughtful about what the rest of the year might look like.

Yes, it's certainly because of the concentration of share program last year, this year is lumpier, and it makes it more challenging in Q3. I think we've talked on an annualized basis we would probably want oil prices in the $75 range to be able to continually stay above the trigger point. But as Vicki made her comments earlier, our intention would be is even as we fall below the $4, that as part of our shareholder return program is continuing to buy back stock. And so even if we fall below the $4, our intention is to continue to return value to shareholders through buybacks.

Our next question comes from Paul Cheng from Scotiabank.

Rob, I would like to revisit the budget. What underlying inflation assumptions did you incorporate into your regional budget? Also, I assume you did not account for any deflation in the second half of the year? How much of your service and raw material costs this year will be affected by spot prices if deflation occurs? That’s my first question. My second question pertains to your earlier remarks about the DJ Basin and the variability of wells coming online for the remainder of the year. What about the situation in the Permian?

Paul, I will address both questions. Regarding inflation, year-on-year, we are experiencing around 15% domestically in the U.S., although internationally, the impact is much less. We had budget plans to mitigate about 5% of that through operational efficiencies, and we are generally on track. In the second half of the year, we are noticing some softening in certain areas. Specifically, for OCTG, we are observing fluctuations in power and fuel costs, as well as labor components, which may present challenges. Additionally, we have several rigs and frac cores operational, so we will feel some impact there. However, we maintain longer-term relationships that allow us to balance pricing with our service partners. We are closely monitoring the OCTG market, and we expect steady performance, but we will assess the broader market trends. Another factor to watch is sand usage; we are increasingly opting for regional sand in the Rockies with our main supplier in the Permian showing promise. While we are not changing our outlook or budget perspective, these are key variables we are keeping an eye on. As for the Permian, we are seeing changes in well counts that are not as drastic as in the DJ Basin. In the first quarter, we had 56 wells online and anticipate reaching a more stable count of around 100 to 110. To provide some context, as Rob mentioned in his remarks, we have focused on development sequencing. The ramp-up and looming weather in the fourth quarter meant we had pads with a lower well count to minimize risk to production. Starting in the first quarter, many of our well pads in the Midland and Delaware Basins are now surpassing 10 wells per pad, which enhances value through more simultaneous operations, yet alters the production sequencing. Despite a low well count and a rising count of drilled but uncompleted wells in the first quarter, we expect to stabilize both metrics as we progress into the second quarter and certainly through the latter half of the year. I hope this clarifies things a bit.

Our next question comes from Leo Mariani from ROTH MKM.

I just wanted to follow up a little bit more on the low carbon venture business here. I guess recently, it came out that you guys invested kind of more money into NET Power here. And I just wanted to maybe get some color around kind of what the sort of confidence is in that business? And why putting the incremental money there? And then sticking on low carbon ventures, I just wanted to see if there was any maybe update on sort of funding for the DACs here at this point in time. Are you all having really detailed conversations out there? Or do you think there could be something that gets done here in '23 in the funding?

I'll start with NET Power. We began exploring NET Power nearly three years ago. We are impressed by the physics and technical aspects of how it operates. It is really the only emission-free power technology that utilizes hydrocarbon gases. Since hydrocarbon gases are abundant in the United States and other regions, we believe that a technology capable of using these gases for power generation will be transformative for the power industry, both domestically and internationally. It combusts hydrocarbon gases with oxygen instead of air, eliminating volatile organics, and the resulting CO2 powers the turbine, which is then captured as part of the process. This technology meets all the necessary requirements and will be essential for others as well. In Appalachia, the abundance of gas from regions like Haynesville, Permian, and DJ presents significant opportunities to deploy such technologies. Our confidence has also increased with Baker now being an equity partner in this initiative, as they are redesigning the turbines for greater efficiency. We anticipate starting construction around 2026, or possibly sooner, and expect the costs to be lower than traditional power plants with carbon capture. We will construct the first unit in the Permian Basin to support our oil and gas operations, and eventually, it will serve as one of the emission-free power sources for our direct air capture units.

Yes. I would like to add that we have initiated the Front-End Engineering Design for our first plant in partnership with the NET Power team, and the timeline for 2026 aligns well with our needs for direct air capture. It also aligns effectively with oil and gas operations to decarbonize our power generation. Additionally, we will be capturing CO2 as a byproduct. As we plan to increase our use of anthropogenic CO2, this approach is very suitable. Regarding the direct air capture, we are considering funding not just for DAC-1 but also for DAC-2 and future projects. This remains a key part of our strategy. We recognize that to succeed in commercial development beyond Plant 1, we will require financial backing to grow in line with the expanding market opportunities. We aim to continue our progress this year and will provide updates as developments occur. Importantly, I mentioned earlier how the progress in the carbon dioxide removal market is influencing our project developments and our approach to financing moving forward. We want to be ready to share substantial updates later this year and into next year as the project advances.

And I guess what I would like to add that too...

Okay. That's clear enough.

Sorry, Leo. I want to mention that as we assess the costs we will incur and the funds we will need to allocate from our free cash flow, we anticipate it will be in the range of $500 million to $600 million over the next two to three years. It's important for everyone to understand that our future capital program for oil and gas development, chemicals, and midstream will be aligned with our established priorities, one of which is investing in ourselves through share repurchases, an essential part of our cash flow priorities. I want to ensure that people recognize we won't allow our capital spending to reach a level that prevents us from executing necessary share buybacks. For instance, last year, out of the $17.5 billion of cash available for debt reduction, share repurchases, and capital programs, 57% was allocated to debt reduction, 17% to share repurchases, and 26% to capital programs. If we encounter a similar cash situation, 40% would go to capital programs, while 55% would be directed to share repurchases, with potentially up to 5% for debt reduction. We are committed to ensuring that our capital does not grow to a point where it limits our ability to repurchase shares at the required level.

Okay. Very thorough answer. Very much appreciate that, guys. And then just a follow-up on your comment on sort of chemicals. EBITDA on the expansion over time kind of eventually getting to this $300 million to $400 million as we get towards '26. You mentioned in the prepared comments that you could start seeing some as soon as late '23. Can that number kind of start to be significant even as early as 2024? Could we get something even like 1/3 of that potential EBITDA next year? Just trying to get a sense of how that would ramp over time.

Yes. Leo, the early days contribution from that is going to be from the smaller expansion project. It's in the $50 million EBITDA range. The $250 million to $350 million number we've given for the battleground project that's out beyond the project in 2026.

The next question comes from Roger Read from Wells Fargo Securities.

Yes. Maybe just 1 quick 1 to clarify off your comment, Vicki, to Leo's question about the CapEx, the $500 million to $600 million per year. That's inclusive of NET Power and DAC or just 1 or the other? I was just want to make sure I understood that.

That represents all of our low carbon ventures capital, assuming we do not secure a partner. We are having very promising discussions with a preferred partner that might lead to results this year or possibly next year. Therefore, we anticipate acquiring some funding. However, we want to emphasize that if we do not, that is the maximum amount we would spend. Alternatively, we could consider a lower expenditure if we collaborate with a partner.

I appreciate the clarification. My other question relates to the goal of maintaining the $4 common repurchase on an annual trailing basis. None of us can predict commodity prices. As mentioned in the presentation, you have one of the largest acreage holdings in the U.S. We've noticed that other upstream companies are reducing their activities or identifying certain areas as noncore, which they won't be drilling or completing in the near future. Is there any acreage or asset sales proceeds that could be used to address any gaps that might arise or to mitigate the variations we might experience ahead? Any information you can provide on this would be appreciated.

We continually evaluate how to make the best value decisions. When considering divestitures as a potential source of funding for ongoing repurchases and preferred share redemptions, that option is certainly on the table. However, our current position is substantial, and when weighing the relative valuations of divesting versus continuing our program, we need to ensure that any decision made is the right one. There are smaller opportunities we could explore, but whether they would be significant enough to sustain our efforts is uncertain at this time. We are also looking into other options, but I doubt those will materialize quickly enough to address the urgent challenges we are currently facing.

There are no more questions in the queue. This concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.

I just want to say in closing that I know there's been a lot of concerns among investors in our industry, particularly with respect to asset quality, execution, and performance. And as Doug had pointed out, I wonder if that's part of the reason for the reaction to what we're seeing today. But looking at our asset quality, I think there's nobody that could question the quality of our assets. And you look at our past performance, I also think that our continuing improvement in well productivity in the Permian and some data that we'll show next earnings call about our performance in the Rockies will clearly show that we're not losing any capabilities. We're not losing any performance. And in fact, looking at what our teams are doing technically today, they continue to innovate, continue to optimize. And with the mention of a new technique in the DJ, there are also new ways of doing things that we're trying in the Permian as well as in our Oman operations, Gulf of Mexico with the subsea pumping and systems installations, starting to look at our seismic differently. I think that for our company, we have not seen degradation in the quality or performance of our teams. And I want to thank our teams for that because they continue to push the envelope and every year get better and better. And so I don't think there should be any concern about where we are today and what we're doing. It's just a kind of a strange scenario where, in the second quarter, it happens to be the lowest of the year, but our production and productivity is continuing to get better. So with that, I want to thank you all for participating in the call today.

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