Good afternoon. Welcome to Occidental's Q1 2023 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 0. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then 1 on your touch-tone phone. To withdraw your question, please press star then 2. 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 Q1 2023 conference call. On the call with us today are Vicki Hollub, President and Chief Executive Officer, Rob Peterson, Senior Vice President and Chief Financial Officer, and Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management. This afternoon, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on slide 2 regarding forward-looking statements that will be made on the call this afternoon. We'll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules to our earnings release and on our website. I'll now turn the call over to Vicki. Vicki, please go ahead.
Thank you, Neil, Good afternoon, everyone. The operational and financial successes we achieved last year continued into 2023, as I will detail in our Q1 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 investor-grade credit rating from Moody's. This afternoon, I will begin by covering our Q1 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.
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 an OxyChem pretax earnings. Our operational success, even in the Q1'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 Q1 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 at 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 continued to perform exceptionally well in the Q1, 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 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 and a half 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 frack designs to reduce acid 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 break-even 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 redemptions may be accelerated. We have previously spoken about how potential future production growth is expected to be in the low single digits.
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-$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 ventures 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 break even, 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 a quarter of our current share repurchase program, enabling us to trigger the redemption of approximately $650 million of preferred equity in the Q1. 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 today by highlighting our March credit rating upgrade and positive outlook for Moody's Investors Service. Regaining a Moody's investment grade rating is a significant milestone to acknowledge Oxy's recent financial transformation. Continued redemption of preferred equity combined with opportunistic debt reduction presents a compelling de-leveraging 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 the preferred equity is triggered when rolling 12-month common shareholder distributions reach 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 Q1 will be fully redeemed. As of May 9th, 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. Even if we fall below the trigger, we plan to continue repurchasing common shares so that the distributions required to surpass the trigger in future quarters are 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 Q1 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 Q1 with nearly $1.2 billion of unrestricted cash, but had not yet made payments to preferred equity holder as of March 31st due to the 30-day redemption notice requirement.
The Q1 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 holder are made. During the Q1, 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 oil realizations as a percentage of WTI, and lower sales and production due to the quarter end timing of cargo liftings in Algeria. We experienced a modestly negative working capital change during the period, which is typical for the Q1, and was primarily driven by similar annual interest payments on our debt, annual property tax payments, and payments under compensation and pension plan.
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 partially reverse in the Q2 since many of these payments are made annually in the Q1 but accrue throughout the year. Discussed in the last call, we expect to be a full U.S. federal cash tax payer 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 Q1 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 asset portfolio.
These factors enabled us to surpass our Q1 guidance. Some are expected to continue having positive impacts 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 Q2 production will be in 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 Q1 of 2023 would 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 1st quarter. In the 2nd quarter, we expect to turn a significantly higher number of wells to production, the benefits of which will be fully realized in the 2nd half of the year. Drilling timing fluctuations are bringing wells online, and the resulting production impact are typically and primarily driven by the optimization of resources and pad development timing. Internationally, we expect production compared to prior 1st quarter, we expect higher production compared to the 1st 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 Q2 oil mix will reduce to approximately 52%, with 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 Q2, 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 Q2 will also contribute to a domestic 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 Q1 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 Q2. OxyChem approximated guidance in the Q1. Due to the seasonality of customers' chlorovinyl inventory orders, we anticipate the first half of the year will reflect stronger results in 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 pre-tax income guidance midpoint to $1.5 billion. Industry and marketing generated pre-tax income of $35 million in the Q1, falling within our guidance range.
Q1 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 from income from WES. Capital spending in the quarter approximated $1.5 billion at close to 25% of our 2023 capital plan, which remains at $5.4 billion-$6.2 billion. We expect higher capital spending in the Q2 compared to the first due to development timing in the Rockies and Permian and advancement of the OxyChem Battleground modernization and expansion project. We also anticipate the capital spending in the third and Q4s will be below the Q2 and in line with full-year guidance. Overall, the Q1 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.
We will now begin the question and answer session. To ask a question, you may press star then 1 on your touch-tone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then 2. Please limit yourself to one primary question and one follow-up. At this time, we'll pause momentarily to assemble our roster. Our first question comes from Neal Dingmann from Truist Securities. Please go ahead.
Morning, thanks for the time. I think my question is, it seems like certainly in the Permian and other areas, you're having very nice and remarkable efficiencies, and then there's a potential for OFS potential softness we've heard about. I'm just wondering if you get the benefits of both those things, would you continue with the plan you had? You know, basically, with those savings, would you just take those free cash flow and plow that back into the buybacks at all, or would you continue with maybe more growth?
No, we would, any incremental cash flow that we can generate from whatever sources would go to share repurchases.
Okay.
The and hopefully, beyond that, the redemption of the preferred along with it.
Okay. Great to hear. Just secondly, DJ, activity. It sounds like you're gonna be really, you didn't have as many in the Q1 as expected, and that's really gonna take off. Maybe could you just comment on as far as, you know, well pads and just, you know, I guess the two questions I had in the DJ? On permitting, I think you're fine there. I just wanted to double-check that. Secondly, just on pad size and all expectations. Are you doing anything different there on the completion side?
Yeah, I'll pass this to Richard.
Hey, Neil. Appreciate it. Yeah, really good quarter and outlooking well for our Rockies team, appreciate really the good pieces that they're putting together. Maybe just connect a couple of things. I think one thing we saw in the Q1 that is playing through all year is very strong base production performance. A lot of that is really strong wells that they brought on the end of last year that were new wells or wedge that are now turned into base. In addition to that, they've been able to continue to optimize their production system. The most meaningful thing they've done, they've introduced gas lift earlier in a lot of these wells and even on some of the legacy base performance, which has really gave us a boost.
We did quite a few of those in the Q1. We'll do less in the Q2, so you won't see quite as much of that bump, but that's been helpful on the base side. On the new well performance side, I mean, obviously, you know, was happy to see we included this peak 24-hour record for this NIOC well. I'd say that's, you know, fundamentally a good thing to see out of our new well performance in the Rockies. You know, we've been able to continue to down space in certain areas similar to how we do our development in the Permian. In many areas where there might have been 18 wells per section, we're down to 12. We've been able to increase our profit concentration to couple with that down spacing.
I've been able to increase that about 30%. Just the efficiency of really the frack and then turning that online, we're continuing to reduce not only the time to market as we traditionally talk about it, but one that the team there has been very focused on, which is a time to peak production. Being very thoughtful about how we're building this operational ramp in for the rest of the year. I guess last couple points, as you said, we had 6 wells delivered in the Q1. That was per plan. Really the Q2 through the end of the year, we anticipate 20-30 wells per quarter, kinda fit that total year outlook.
Definitely, you know, picking back up on that in terms of well delivery. You know, bottom line, if you look at the first half and the second half, as we communicated on the last call, we expected some decline just through really the cycle of under-investment as we picked up, you know, activity in the second half of last year. That will, we'll be able to then turn to growth for the second half of the year. Both of those are looking better than original plans, so very pleased with the team there.
Our next question comes from Neil Mehta from Goldman Sachs. Please go ahead.
Yeah, thank you. The first question is more of a short-term question, then the second is around low carbon. Just in the quarter, it looked like price realizations were a little bit soft. So some of that, it sounds like was just around turnarounds, in, on the refining side. Can you just talk about that and clarify, as it drives some delta versus consensus?
Well, Neal, I think there were 3 key components of that. First of all, you know, looking at the calendar month average roll in terms of the NYMEX price, I mean, with seeing the market switch really from backwardation to contango at the end of March impacted realizations by about $1.50 per barrel. Starting there across the domestic portfolio. Following that, in terms of the Gulf of Mexico, it had an amazing quarter. At the same time, there were refineries on the Gulf Coast that had turnarounds going on. Moving from the Q4 to the Q1, 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.
It was those components all together that really impacted, oil realizations.
Yeah, that's really helpful. If you could give an update on the low carbon business, as you progress towards DAC 1, what is, what's the latest in terms of the development, and then your thoughts on the voluntary market as well, as that can help to bring the project closer to the money?
I'll start with, we had a very exciting, official groundbreaking, finally, on the Low Carbon Venture business, DAC 1, that we'll be building in the Permian Basin. It's already under construction. The work started at the end of the last quarter. We had an official naming at the groundbreaking. It's now called STRATOS. Currently, moving along very well, and we're really excited about it and excited about where the teams are headed with it. You wanna talk about the carbon market?
Yeah, sure. Maybe just add broadly on a couple other updates on kind of the low carbon progress. Like Vicki said, obviously moving with DAC 1 in the Permian, and then continue to progress, you know, our sequestration hubs in the Gulf Coast. Continue to move forward kind of with the subsurface understanding or the work that we're doing there. Really the, you know, big piece of that, we've submitted 2 more Class VI wells in our hubs there and then 2 more to support our Permian operations. Continue to do that. In the King Ranch area, we're making plans to drill we call 3 stratigraphic kind of test wells. Those go in front of the Class VI submissions there.
Continue to do really that upfront work to kind of prepare, you know, for development, both from the point source side and the DAC side in both those areas. In terms of the market, you know, continue to see the voluntary market strong or growing for our CDR sales. I think we'll anticipate having some updates on that over the next few months, getting close to some meaningful things there. You know, I think a lot of that is really, you know, turning to the compliance market as well as really globally, as we've talked about things around heavy duty transportation and specifically airlines have continued to sort of form up.
I'd say sustainable aviation fuels, especially in Europe, have continued to recognize kind of these carbon removals as part of that portfolio solution. We're seeing some policy form in addition to what we see in the U.S. with the IRA to kind of help support that. You know, the voluntary market's in front of that. We appreciate, you know, working with some strong partners there that understand the role of carbon removals, understand the emergence of these compliance markets, they're really doing their part to help us catalyze this technology, bring those costs down while we fit, you know, that long-term compliance market need.
More updates, I think, you know, we hope to give later this year as that makes more progress, but, you know, certainly fitting within the ranges and the expectations we have on the revenue side, for our DAC projects.
Our next question comes from Doug Leggate from Bank of America. Please go ahead.
Thank you. Appreciate you taking my questions. I guess I've got a couple of follow-ups. I mean, watching your share price reaction last night to the earnings, the market obviously saw something it didn't like, and it struck me at least that a lot of the people that cover you didn't cover Anadarko and perhaps don't remember the seasonality of Gulf of Mexico maintenance. I wonder if you could just take a minute to explain how you're running that business as it relates to the seasonality of production.
Yeah. Thank you, Doug, for bringing that up. Yeah, you're right. I think that that's not very well understood. What's happened with us now, in terms of our forecast for Gulf of Mexico is, you know, I wanna make sure everybody realizes this is, this is pretty typical. What's different for this year is that we had such an incredible Q1. The reason that we had such an incredible Q1 is because, first of all, we had the lowest downtime that we'd had in a while. It was a very, very, very good performance, operating performance by the teams in the Q1 in Gulf of Mexico. Secondly, we had the Caesar Tonga subsea system excellence, or expansion system come online.
From Caesar Tonga, we had an incremental increase of a gross 15,000 barrel per day from that project. Our Q1 was really propped up by some good performance, lower downtime, and the transfer of what would have been the Horn Mountain maintenance in Q1 to Q2. The reason we moved that from Q1 to Q2 was just some supply chain issues in getting the materials we needed from the supplier. This would have looked like any normal year if we had been able to do the maintenance as we had planned to do. Now I think what's gotten people concerned is going from 171 to such a lower number in the Q2.
Horn Mountain is one of the biggest producers that we have offshore, so doing that maintenance in a given quarter is impactful. Along with that, we have another couple of maintenance projects on the schedule along with some well work that we wanna do. The full year still looks really good. We're at 144 thousand barrels a day, so that hasn't changed. It's just the timing and how it looks much lumpier than we're used to and than others are used to. Again, it's because of the bigger maintenance that wasn't done in Q1 that will be done in Q2, along with much higher production than we than people are used to seeing. Thanks for the question.
Yeah, I appreciate the, I appreciate the clarification, Vicki, because it's remarkable that that would seem to be the primary focus of discussions after the re-the result last night, and I just thought it'd be worth reminding everyone that legacy Anadarko, that was entirely normal. Thank you for the clarification. My, my follow-up is really, I guess it's a Rob question, but you mentioned inflation, Rob, or at least I think Vicki did in her remarks, that things might be rolling over a little bit. Your CapEx guidance is still quite wide. I wonder if you could just, you know, give us a tip of the hat as to where you see the trend going.
Should we be starting to think that you've got a chance of coming in towards the lower end of that range, or is that more activity-led, or is it more, you know, had you already baked in a reasonable amount of inflation that might not now happen?
I think as discussed in Vicki's comments, and 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. I wouldn't say we're ready to commit to the fact that things are gonna roll over and decline for the balance of the year. 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 re-allows us to continue the same level of activity for a lower cost, we would roll that back into additional share purchases in the balance of the year. Richard probably has some additional comments.
Yeah, I would. No, that's perfect, Rob. I just was going to add 1. I'd say the other element we factor in is continued efficiency improvement. You know, Doug, ramping up last year, getting started this year, kind of hitting steady state with our rigs and our frac cores, we do expect, you know, continued efficiencies. I mean, we highlighted on these singular wells of these records, but it's really in total, you know, we're anticipating some improvement in the second half of the year. We leave a little bit of room on that where it, you know, the burn rate just gets a little faster as we gain in efficiency.
Our next question comes from John Royall from JP Morgan. Please go ahead.
Hi, good afternoon. Thanks for taking my questions. My first question's on chemicals. You were in line in 1Q, but you raised your full-year guide. You're seeing something that's giving you more confidence in the remainder of the year. It does feel like there should still be some challenges to the housing market. Just looking for some color on the guidance raised in chem so early in the year and what appears to be an uncertain environment.
Yeah, John, I think, I think you've characterized it actually pretty well in your question. If you look at domestic PVC demand through the Q1, 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 Q1 as it's up almost 80% year-over-year. We end up with a combined demand for PVC that's up about 2.5%, 2.7% for the country versus last year. That driving on that softness of domestic demand, as we discussed on prior calls, is really being driven by the housing and construction sector. We still believe that inventories remain low for many PVC buyers as we're entering sort of the heart of construction season.
No doubt, the discouraging 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 year for construction. Our guidance reflects that continued uncertainty in the trajectory of the global business, and the domestic business. We still are 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, you know, the lower energy prices in terms of gas prices, resulting in lower ethylene prices also does create the opportunity for some margin in the business that might still be present and stickier that even at these lower demand levels. That's part of the raise.
I would say in the caustic side of the business, we're seeing, you know, this sort of balanced along tight conditions. General manufacturing is certainly off from prior year, particularly automotive remains subdued. Domestic demand is similar to last year, but availability is certainly higher than it was before. We're seeing that result in some price erosion continually in the caustic side of the business. We're still assuming that the unwinding of inventories in Europe take the balance into the middle of the year, and that the Chinese economy continues to open slowly. If either one of those happen more rapidly, that would certainly be favorable to the business.
That increase in guidance really reflects some optimism around things kind of reaching a stability point, at least the next quarter or so, and then, the preserving some of the margins with lower feedstock costs.
Great. Thank you. Then, my next question's on the pay down 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? Just assuming we stay above it, is that $700 million-ish run rate, including the premium, a good go forward clip to think about?
I would say it's just based on the cash available. We're gonna use the free cash that we have to continue to buy shares and to trigger the preferred as we can do that. We're monitoring that. We have an outlook on that, so we're being pretty thoughtful around what the rest of the year might look like.
Yeah, it's certainly with the concentration of share program last year, this year's 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. As Vicki made her comments
Earlier, our intention would be is even as we fall below the four, that as part of our shareholder return program is continuing to buy back stock. Even if we fall below the four, our intention is to continue to return value to shareholders through those buybacks.
Our next question comes from Paul Cheng from Scotiabank. Please go ahead.
Thank you. Good morning. Just Rob, just want to go back into the budget. What's the underlying inflation that you included in your regional budget? Have you. I suppose that you didn't really build into any deflationary in the second half. How much is your service and raw material for this year will be subject to the spot prices, if we do see deflationary? That's the first question. Second question is that, I think, in the prepared remarks, talk about on the DJ Basin that for the remaining of the year, the well, come on stream will be pretty variable each quarter. How about in the Permian? Thank you.
Hey, Paul. Let me, I'll try to start on both of those. In terms of really in-inflation, when we look year-on-year, we're around 15%. This is domestic in the U.S. Of course, internationally, we didn't see near that. But in the U.S., looking at around 15%, we had plans that were embedded in our budget to offset about five of that through operational efficiencies. We're generally on target for both. Let me deconstruct kind of the second half and then a few of the bigger components. The second half of the year, you know, we are seeing some things soften. When you think about OCTG, obviously power costs and fuel, some of the labor components, those are types of things that we see as potential.
You know, we also have quite a few of our rigs and frac cores that are up. We'll be exposed a little bit either way there, though, like we talk about, we have longer term relationships and we're able to balance kind of that long term with short-term pricing with our service partners on that front. The big areas we're looking for is continuing to kind of watch the OCTG market. We'll see what rigs and fracs do this year. Obviously we're steady, but we'll see what the rest of the market has to do. Probably the other point that, you know, we would watch or that would impact us is sand. We're using more regional sand, even in, you know, the Rockies.
There's some different sand choices, but our primary supplier there continues to be in front in the Permian, and so we're seeing some opportunity on that. At this point, we're not looking to change our outlook or kinda change the way we're thinking about the budget, but we did wanna note those are the key variables that we're watching that will impact us. In terms of the Permian, you know, similar sort of well count type change, not quite as drastic as what we're seeing in the DJ, but we had 56 wells online in the Q1. We'll see that kinda hit more steady state of around 100, 110.
Really, you know, what happened, just to give a little bit more color, as Rob kinda said in his prepared remarks, you know, a lot around development sequencing. If you think about the ramp up and then going into the Q4 where you're exposed to weather, we had pads with smaller well count. We did that to really de-risk kind of the production in the Q4, and really it was production in the Q1. As we started in the Q1, many of our well pads, Midland Basin, Delaware Basin, they've gone north of 10 kinda wells per pad, so you have a lot more SIMOPS. That's better from a value standpoint, but it does change kind of that sequencing of production online.
We do see, while the well count was low and the kinda residual DUC count grew for us in the Q1, we expect to hit steady state really on both of those as we go into the Q2 and definitely in the second half of the year. Hopefully that helps a little bit there.
Our next question comes from Leo Mariani from Roth MKM. Please go ahead.
I just wanted to follow up a little bit more on the low carbon venture, you know, business here. I guess recently it came out that you guys invested, you know, kinda more money into NET Power, you know, here. I just wanted to maybe get, you know, some color around, you know, kind of what the, what the sort of confidence is, you know, in that business and why putting the incremental, you know, money there. Sticking on low carbon ventures, just wanted to see if there was any maybe update on sort of funding, you know, for the DACs here at this point in time. Are y'all having, you know, really detailed conversations out there?
Do you think there could be something that gets done here in 2023 on the funding?
I'll start with Net Power. We started looking at Net Power about over 2 years ago, almost 3 years ago. The reason we like it is because the physics and the technical aspect of how it works is impressive. As we've, I know, mentioned on this call before, it's really the only source of emission-free power technology that uses hydrocarbon gases. With hydrocarbon gases being so plentiful in the United States and in other areas of the world, we felt that a technology that actually can continue to use gas, hydrocarbon gas for the generation of power is going to be incredibly transformative for the power industry, not just here in the United States, but internationally as well. When you look at it combines hydrocarbon gases, combusts hydrocarbon gases with oxygen instead of air.
You have no volatile organics. The CO2, which is created, drives the turbine, and then it's captured as part of the process. It does all the things that we need it to do and that other companies will need as well. You look at the Appalachians, all the gas there, the gas in the Haynesville, the gas in the Permian and the DJ, it creates a lot of opportunity to build a lot of these things. Our confidence was bolstered also by the fact that we have now Baker as an equity owner in this process, and they are redesigning the turbine to make it more efficient.
When we are able to start building this, which should be in the 2026 timeframe or maybe a little bit before, we expect that the cost of this will be less than what a traditional power plant would be if you put carbon capture on it. It's a very flexible technology. We will be building the first one of those in the Permian Basin to provide power for our oil and gas operations. In the future, it'll be one of the emission-free power sources that we use for our direct air capture units.
The only thing I would add on Net Power, like Vicki said, we've started FEED on that first plant with the Net Power team. Again, that 2026 timeframe lines up very well to not only what we need for direct air capture, but it's a great fit for oil and gas operations to help decarbonize the power obviously that we have. The other offtake of that is CO2. As we look to really transition and be able to use more anthropogenic CO2, it's a great fit. On the DAC, and then Vicki can help with this too, I think, you know, continue to, you know, think about funding not only for DAC 1, but especially for DAC 2 and beyond. To reiterate, that is absolutely our plan.
You know, we know that with commercial development success as we go beyond plant 1, we really will need that financial support to be able to develop as we see the market growing for us to fit into. I think, you know, we want to continue to progress this year. Obviously, we'll give updates on any of that as it comes forward. Meaningfully, as I answered earlier, kind of the market or the CDR sales, cost progress on the project, and then kind of how we think about the capitalization as we go forward. We, you know, want to be prepared as we go late this year and into next year to be able to give meaningful updates as that project continues.
I guess what I'd like to add to that too.
Okay. That's, that's really helpful.
Sorry, Leo.
Sorry.
One thing I'd like to add to that is that, as we look at what the cost of this is going to be for us and what funds we will have to provide out of our free cash flow, basically it would be in the $500 million-$600 million dollar range. It wouldn't be a lot more than that over the next 2-3 years. I want everybody to understand that, looking forward, our capital program for our oil and gas development, chemicals, midstream, the corporation's capital is going to be invested in a way that fits with the priorities that we've established. One of which, and as important as any of the others, is investing in ourselves. That is the repurchase of shares.
That's a big part of our of our cash flow priorities, and I wanna make sure that people don't think that we're going to in the future have capital spending so much that we can't accomplish that. For example, last year, we out of the $17.5 billion of cash that we had available to those three buckets, to debt reduction, share repurchases, and capital programs, 57% went to debt reduction, 17% to share repurchases, and 26% to our capital programs. If we had a similar situation with that kind of cash, 40% would go to capital programs, but 55% would go to share repurchases and potentially up to 5% for debt reduction.
This is something that we're very committed to, is not to let our capital grow to a point where it's not able to buy back shares at the level that we really need to do.
Okay. Very, very thorough answer. Very much appreciate that, guys. Then just to follow up on your comment on sort of chemicals EBITDA on the expansion over time, kind of eventually kinda getting to this $300 million-$400 million as we get towards 2026. You mentioned in the prepared comments that you could start seeing some as soon as late 2023. You know, can that number kinda start to be significant even as early as 2024? You know, could we get, you know, something even like a third of that potentially EBITDA, you know, next year? Just trying to get a sense of how that would ramp over time.
Yeah. Leo, the early days contributions from that's gonna be from the smaller expansion project. It's in the $50 million EBITDA range, the 250-350 number that we've given for the Battleground project that's out beyond the project in 2026.
Thank you. Appreciate it.
The next question comes from Roger Read from Wells Fargo Securities. Please go ahead.
Yeah, thanks. Good morning. Maybe just one quick one to clarify off your comment, Vicki, to Leo's question about the CapEx, the $500 million-$600 million per year. That's inclusive of NET Power and DAC or just one or the other? Just wanna make sure I understood that.
That's all of our low carbon ventures, capital.
Okay, great.
That is assuming that we don't bring in a partner. We are having some really good conversations with, in fact, with one with a preferred partner that could materialize maybe sometime this year, or if not this year, next year. We do expect to get some funding. What we wanna make sure we re-relay to you guys is that if we don't, that's the maximum of spend that we would have. Otherwise, we're looking at potentially having a lower spend than that with a partner.
Okay. Appreciate the clarification. My other question, and this ties into the goal of maintaining the $4 of common repurchase on an annual trailing basis. None of us know what the commodity price is gonna be. You've got, you know, as pointed out in the presentation, right, one of the largest acreage holdings in the U.S. We've seen some of the other upstream companies, you know, trimming back a little bit or identifying some things as, I guess, we could call it non-core or something they simply won't be drilling and completing anytime soon. Is there any acreage or other type of asset sales, you know, proceeds could be used to sort of plug those gaps if they arise or to offset the lumpiness that's coming forward? Just anything you can offer on that front would be appreciated.
Well, one of the things we do is we're always looking at how do we make the best value decisions. When we think about divestitures, being a source for funding to continue the repurchase and the redemption of the preferred, that's certainly an option that we would consider. The reality of where we are today, though, is that our position is large. When you do the relative valuations of divesting versus for the continuation of this program, you have to make sure that you're making the right decision there. I would say there's smaller things that would be optional for us to potentially do. Whether it would be large enough scale to continue it is the question at this point.
We are considering other options that I doubt would mature soon enough to be able to meet the cliff that we're facing right now.
Great. Thank you.
Again, if you have a question, please press star then one. 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'd just like 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, performance. As Doug had pointed out, I wonder if that's part of the reason for the reaction to what we're saying today. 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.
In fact, looking at what our teams are doing technically today, they continue to innovate, continue to optimize. 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. I wanna thank our teams for that because they continue to push the envelope and every year get better and better. 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 Q2 it happens to be the lowest of the year. Our production and productivity is continuing to get better. With that, I wanna thank you all for participating in the call today.
Conference is now concluded. Thank you for attending today's presentation. You may now.