Occidental Petroleum (NYSE:OXY) reported third-quarter financial results on Tuesday. The transcript from the company’s third-quarter earnings call has been provided below.
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Summary
Occidental Petroleum exceeded production guidance and achieved a $10 billion principal debt milestone, marking significant progress in its financial strengthening efforts.
The company plans to add more than $4 billion of annual sustainable cash flow by 2030, driven by cost efficiencies, lower decline rates, and reduced debt interest.
Operational highlights include strong performance in U.S. onshore and the Gulf of Mexico, with advances in enhanced oil recovery and AI-driven production optimization.
Future guidance indicates production between 1.43 and 1.47 million BOE per day for Q4, with ongoing focus on debt reduction and sustainable dividend growth.
Management emphasized the strategic importance of CO2 supply agreements for EOR, improvements in AI application across operations, and the potential for exploration in Peru and Colombia.
Full Transcript
OPERATOR
Good afternoon and welcome to Occidental Petroleum’s third quarter 2026 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the Star key followed by zero. After today’s presentation, there will be an opportunity to ask questions. To ask a question, you may press Star then one on your touchtone phone. To withdraw your question, please press Star then two.
Please note today’s event is being recorded. I’d now like to turn the conference over to Babatunde Kul, Vice President of Investor Relations. Please go ahead.
Babatunde Kul (Vice President of Investor Relations)
Thank you, Rocco, and good afternoon, everyone, and thank you for participating in Occidental Petroleum’s third quarter 2026 earnings conference call. On the call with us today are Richard Jackson, President and Chief Executive Officer; Sunil Mathew, Chief Financial Officer; and Ken Dillon, Senior Vice President and President, International Oil and Gas Operations. This afternoon we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on slide 2 regarding forward-looking statements that will be made on the call this afternoon. We’ll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules to our earnings release and on our website. I will now turn the call over to Richard.
Richard A Jackson (President and CEO)
Thank you, Babatunde, and thank you all for joining our call today. This was another strong quarter for Oxy, and I would like to thank our teams for their continued focus on execution and consistent results. This quarter, we exceeded the midpoint of guidance for total company production, delivered strong results in midstream with over $300 million in adjusted pretax income, and continue to drive efficiencies across our operations. A key highlight in the third quarter was achieving our $10 billion principal debt milestone, which is an important step in strengthening our financial position and creating additional capacity to deliver value.
Last quarter I shared our pathway to add more than $4 billion of annual sustainable cash flow by 2030, an approximate 95% increase compared to 2025. Importantly, this increase is driven by durable improvements across the business, including oil and gas cost efficiencies, lower decline rates, and lower debt interest. Looking ahead, we remain focused on executing this value improvement plan and on increasing and accelerating both the return on and the return of capital through the cycle.
A key part of delivering this value improvement is our ability to unlock more from the subsurface through advanced resource recovery. We were recently able to share and post a more detailed disclosure to demonstrate these capabilities, including our enhanced oil recovery operations. I would like to take a few minutes today to share these highlights before we get into third quarter results. Importantly, we apply our advanced recovery approach across the portfolio and at every stage of resource recovery, from exploration and subsurface characterization through field development and production. This has resulted in a track record of adding and improving our resources while consistently delivering more production. In U.S. unconventional, our new well performance continues to deliver in both productivity and cost efficiency across U.S. unconventional.
Our 2025 and 2026 wells have delivered top-tier performance in every basin, with at least 10% above the industry average on a six-month cumulative oil per lateral foot basis. That performance is driven by the detailed, customized subsurface work we do for every drill spacing unit and well. In the Delaware, for example, we’ve shown that in some areas increasing the number of wells per bench can deliver the same individual well performance and up to two and a half times the recovery per DSU.
We also highlight how we apply the optimal approach for each DSU, whether that is multi-bench co-development or a phased bench development. The aim is to maximize value by aligning our subsurface approach with the right technology, infrastructure, and operating considerations. In conventional EOR, we have over 50 years of experience and 2 billion BOE of resource. Most of this resource is across our 1.2 million acre position on the Permian Central Basin Platform, where we continue to expand EOR development leveraging our extensive CO2 infrastructure. This year our teams also found new ways to add resources and accelerate production through horizontal development in zones we have historically bypassed. Today we are applying unconventional drilling and frac techniques to these zones and are seeing strong results.
To date in 2026, we have drilled eight conventional grassroots horizontal wells that are competitive in our portfolio, with high oil-cut production and lower decline. At the same time, we started an EOR sidetrack program to accelerate production in these same reservoirs by leveraging existing wellbores and infrastructure. After starting these sidetracks in late February, we have now drilled approximately 80 so far this year. This dual approach is both lower cost and efficient to further advance this resource opportunity while adding production.
This year we have already identified 500 more sidetrack candidates to continue to accelerate production. Additionally, our new conventional horizontal opportunities add more than 200 million BOE of development-ready resource with further upside through appraisal and CO2 EOR. In unconventional EOR, we have another 2 billion BOE of resources identified today. Our first three commercial projects are progressing towards injection by 2029, with more than 30 additional development-ready opportunities in the pipeline. Over the last 10 years we piloted our approach across multiple basins and formations, demonstrating significant oil production uplift and economic, miscible gas and CO2 utilization. These pilots have demonstrated approximately 45% uplift, with further upside from additional injection.
In addition to CO2 EOR, we continue to advance a broader suite of technologies where, applied together, we see the potential to increase estimated ultimate recovery by 70% to 140% per well. Additionally, in the Gulf of Mexico, we are advancing waterfloods that give us another significant opportunity to recover more from existing fields and infrastructure. We have identified roughly 450 million BOE of waterflood resource at less than $40 breakeven, providing more than a decade of development runway today.
Importantly, we also continue to outperform base production in U.S. onshore operations. We have averaged more than 13,000 BOE per day above our original annual plan in each of the last three years. A key driver of this outperformance is our continued advancement and application of technology and AI across our operations. To date, approximately 9,000, or 68%, of our artificial lift wells are under AI surveillance, with predictive intelligence supporting up to 7% annual production uplift and reducing failure frequency by 22% compared to 2023.
Together, our advanced recovery technologies and approach help us add and improve resources while continuing to drive cost efficiencies. They also play a significant role in reducing Oxy’s overall decline rate from approximately 25% to 20%, supporting our sustainable cash flow improvement plan by 2030. I’ll now turn to a few specific third quarter operational highlights. Our teams delivered another strong quarter, building on the operational and financial performance we have seen throughout 2026. Our U.S. onshore business outperformed the midpoint of guidance by 20,000 BOE a day. In New Mexico, we hit record gross operated production of 284,000 BOE per day, up about 23% since January. In the Powder River Basin, we ramped up activity and brought a record 27 wells online in the third quarter, which is more than any prior year.
This drove more than 70% production growth compared to the first quarter, with an average net production of 23,000 BOE per day in the third quarter. In the Gulf of Mexico, while third quarter production was affected by third-party gas pipeline constraint and maintenance, we continue to advance our waterflood program. Our first project, the King Dump Flood, began first injection in July, supporting the broader waterflood opportunity across our Gulf of Mexico portfolio.
In our EOR business, we continue to outperform and accelerate production, and our sidetrack program and conventional horizontals have added 10,000 BOE per day as of the end of the third quarter. This demonstrates how our teams were able to adjust this year as we reallocated capital and expense dollars to this fast-track opportunity. As we continue to expand our EOR opportunities, we are also making progress on securing low-cost CO2. We have signed offtake agreements with two project developers to deliver 2 million metric tons per year of anthropogenic CO2 captured from third-party gas processing plants for use in our Permian EOR operations, which represent about 15% of our 2026 purchased CO2. These projects remain subject to final investment decision, which is expected early next year, and represent tangible steps towards expanding access to low-cost CO2 to support our long-term EOR opportunity.
Turning to Stratos, we continue to make progress on the non-technology-related repair, where we are adding structural supports to the calciner. We’ve also been making good progress commissioning unit operations. To date we have captured over 2,000 metric tons of atmospheric CO2 as part of building our pellet inventory. We remain on track to begin full plant startup around the end of the year as we transition to operations in 2027. This strong business performance strengthens our pathway towards adding more than $4 billion of annual sustainable cash flow by 2030 through improved capital efficiency, lower costs, and lower decline rates. We are already seeing progress on these key milestones in our plan. This year we remain on track to deliver more than 7% improvement in new well costs and are tracking towards a 3% improvement in domestic LOE and transportation despite higher prices for CO2, diesel, and other categories impacted by commodity prices.
These improvements, together with higher near-term oil prices, have allowed us to accelerate our balance sheet progress and debt interest savings. We have achieved our $10 billion principal debt milestone and are now establishing a new milestone of $6 billion. As we look towards 2027, under mid-cycle price scenarios, we will have opportunity to make meaningful progress towards our new principal debt milestone and expand our financial capacity for the preferred redemption in August of 2029 and accelerate our broader return of capital opportunities.
At lower prices, our sustainable cash flow progress will focus on supporting principal debt reduction, and we will continue to make structural improvements across the business to grow a sustainable dividend at $50 WTI. In total, as we continue to execute our plan and improve our sustainable cash flow, we will be increasingly well positioned to deliver value and advance our cash flow priorities. I’ll now turn the call over to Sunil to review the financials and to give more detail on these prior.
Sunil Mathew (Chief Financial Officer)
Thank you, Richard. In the third quarter, we generated adjusted earnings of $1.91 per diluted share and reported earnings of $1.61 per diluted share. The difference was largely driven by mark-to-market losses in marketing and crude hedges. Continued operational execution and cost discipline, combined with higher commodity prices, enabled us to generate approximately $2.8 billion of free cash flow. During the quarter, we achieved our $10 billion principal debt milestone, marking another significant step in strengthening Occidental Petroleum’s financial position. We repaid $1.8 billion of principal debt, bringing total year-to-date repayments to $10.4 billion, while ending the quarter with $3.9 billion of unrestricted cash. This progress gives us additional flexibility as we continue to strengthen our balance sheet and advance our cash flow priorities.
Total production averaged 1.43 million boe per day, exceeding the midpoint of guidance by 7,000 boe per day. Strong base and new well performance across our U.S. Onshore assets drove higher volumes, more than offsetting lower-than-expected production in the Gulf of Mexico and international. Gulf of Mexico production declined during the quarter as maintenance activities and a third-party gas pipeline constraint required us to temporarily curtail production at certain facilities.
Production was fully restored by late October. International volumes were marginally lower primarily due to a change in gas processing mode to ethane rejection at Dolphin. Continued operating efficiencies contributed to lower domestic lease operating expense of $8.54 per boe, outperforming our guidance for the quarter. Midstream and marketing also outperformed, driven by stronger-than-expected sulfur pricing and sales volumes at Al Hosn. We also benefited from higher crude marketing margins due to timing impacts of cargo sales and commodity price movements, which are offset in mark-to-market. These factors contributed to adjusted pre-tax income of $309 million.
Improved Permian gas realizations in the Oil and Gas segment largely offset the impact of narrower Waha-to-Gulf Coast spreads on Midstream earnings. Looking ahead to the fourth quarter, we expect total company production to range between 1.43 and 1.47 million boe per day. Our guidance reflects Gulf of Mexico production curtailments related to the third-party gas pipeline constraint, which extended into the fourth quarter, as well as the impact of the hurricane in early October. Excluding temporary downtime impact in the Gulf of Mexico, our full-year production guidance is slightly above the guidance we provided last quarter.
Domestic lease operating expense is expected to increase in the fourth quarter due to higher CO2 costs and an increase in short-cycle, high-return workover opportunities. In Midstream and Marketing, we expect lower gas marketing income as additional Permian gas takeaway capacity comes online in the fourth quarter, along with lower sulfur pricing at Al Hosn. Our strong third quarter results and improved fourth quarter guidance support full-year guidance of $2 billion in adjusted pre-tax income. We expect total company capital spending to be approximately $1.3 billion in the fourth quarter, keeping full-year 2026 capital spending within our original guidance range.
As Richard shared, we continue to make significant progress strengthening the balance sheet and advancing our sustainable cash flow improvement plan. We achieved our $10 billion principal debt milestone ahead of expectations, accelerating interest expense savings. Consistent with what we have said previously, our focus is to further reduce net debt with a preference to continue lowering principal debt. In line with this framework, we are establishing a new principal debt milestone of $6 billion.
Beyond the $6 billion principal debt milestone, we will remain flexible in balancing further principal debt reduction with building cash ahead of the preferred equity redemption in August 2029. We plan to evaluate opportunistic share repurchases once we achieve a net cash position. A sustainable and growing dividend remains a foundational cash flow priority. Last quarter, we announced a second 8% increase to a quarterly dividend for 2026. Future increases will remain measured and disciplined, supported by a strong balance sheet and progress on annual sustainable cash flow improvement.
At $6 billion principal debt, our go-forward interest expense run-rate will be approximately $400 million, or approximately $1 billion lower than our 2025 interest expense, providing the opportunity for durable dividend increases through the cycle. As we shared on previous calls, our starting point for 2027 capital spending remains approximately $5.9 billion. At that level of investment, we continue to expect relatively flat production compared to 2026. The program includes continued investment in mid-cycle projects that are expected to reduce our base decline and sustaining capital over time, including Gulf of Mexico waterflood projects, Permian EOR, and select international opportunities.
These investments are an important part of our plan to lower Occidental Petroleum’s total base decline from approximately 25% to 20% and reduce sustaining capital to approximately $4.5 billion by 2030. We also expect continued well cost and operating efficiencies across Oil and Gas to contribute to that progress and drive higher sustainable free cash flow. The 2027 program will advance our plan to deliver more than $4 billion of annual sustainable cash flow improvement by 2030 relative to 2025. Based on the initiatives underway, we expect approximately $700 to $800 million of sustainable cash flow improvement in 2027 relative to 2026, including lower interest expense, roll-off of STRATOS capital, and additional Oil and Gas efficiencies. Combined with the improvement expected in 2026, this would bring our annual sustainable cash flow improvement to approximately $2 billion by year-end 2027, nearly half of our 2030 objective.
As we finalize our 2027 plan, we will remain disciplined, flexible, and prepared for market volatility. We will share more on our 2027 capital plan on the fourth quarter call, following Board approval. I will now turn the call back to Richard for closing remarks.
Richard A Jackson (President and CEO)
Thank you, Sunil. We’ve made meaningful progress this year, and our teams continue to execute and outperform as we track towards adding more than $4 billion of annual sustainable cash flow by 2030. Our operational performance, continued cost efficiencies, and achievement of the $10 billion principal debt milestone demonstrate that progress. Reaching our next $6 billion milestone will be another important step towards expanding our financial capacity and accelerating the return of capital to shareholders.
Ultimately, we’re building a business that can perform through the cycles and create increasing and durable value for shareholders. With that, we would like to open it up for questions. As a reminder, Ken and Babatunde are also here with us today for Q&A.
OPERATOR
Thank you. We will now begin the question-and-answer session. To ask a question, you may press star, then one on your touchtone phone. If you are using a speakerphone, we ask that you please pick up your handset before pressing the keys. To remove your question, please press star, then two. Please limit questions to one primary question and one follow-up. If you have further questions, you may re-enter the question queue at this time. We will pause momentarily to assemble our roster.
And today’s first question comes from Neil Mehta at Goldman Sachs. Please go ahead.
Neil Mehta (Analyst)
Good morning, Richard. It’s the Neil team. Thanks for taking the time. You know, I guess the first question is the $6 billion debt target. How did you come up with that number? Why is that the right number? And when you look at the forward curve, when do you think you can hit that number? You know, we were thinking maybe it’s end of 2027, and at that point should we assume that you’re in a position to be returning capital by 2028?
Richard A Jackson (President and CEO)
Great, thanks, Neil. I’m going to start and then let Sunil go into some of the details on the play-out of our priorities. I guess first, just in context of the $6 billion, first to say very pleased with the progress of our plan — we’ve been able to continue to accelerate really most components. I think one thing I’d like to say as we get into the priorities and where it fits, we want to remain very focused, clear, and consistent, and I think that has really been a part of the plan that we put together.
Part of that is the ability to accelerate in terms of our cash flow priorities and accelerate return of capital. I think where the $6 billion is building capacity really at any price. So we think about building capacity for the dividend at lower prices like $50, but at mid-cycle, as we’re talking about, we’re able to accelerate a broader return of capital plan. I think the priorities for us stay the same internally: continue to improve the balance sheet, continue to improve resources, continue to improve cost efficiency, and then follow our disciplined cash flow priorities.
So I think that $6 billion is an important step in terms of principal debt that really provides that capacity and clarity as we go into the steps of our cash flow priorities. But let Sunil walk through that and help on how we got there.
Sunil Mathew (Chief Financial Officer)
Hi, Neil. You know, we’ve made significant progress on strengthening our balance sheet, and the principal debt milestones that we set were based on achieving certain leverage metrics. It was primarily debt to EBITDA. So at principal debt of $10 billion, the debt to EBITDA was approximately 1 at $60 WTI, and at principal debt of $6 billion, the debt to EBITDA is around 1 at $50 WTI, which is what we would like to maintain in the long term. Also, at $6 billion principal debt, based on our debt to EBITDA metric and normalized for prices, our balance sheet will be the strongest that we have been in a decade.
Once we achieve our $6 billion principal debt milestone, we will balance additional principal debt reduction and building cash based on the macro and timing relative to the preferred redemption in August 2029. And with respect to your question on 2027, you know, as we look at 2027 at mid-cycle or even current strip prices, we will have opportunity to make meaningful progress towards our new $6 billion principal debt milestone, which expands our financial capacity for the preferred redemption and accelerates our broader return of capital opportunities.
So once we get there, we plan to evaluate opportunistic share repurchases, and especially once we get to a net cash position. So we don’t want to say when in ’27 we would get there, but you can assume that we would definitely get there and potentially a net cash position in 2027. And I would say in terms of dividend growth, as we look at total cash flow priorities, in terms of dividend growth, we will be measured, ensuring that we can support it through the cycle through a combination of strong balance sheet and increasing sustainable cash flow. So the progress on both of these will determine how we think about dividend growth and, accordingly, recommend to our Board.
Neil Mehta (Analyst)
Thank you, Sunil and Richard and team. Just your thoughts on the trajectory of Gulf of Mexico production. You produced 110 in the quarter because of some outages. You kind of guided to plus-minus 115 in Q4 for boe/d. We were thinking next year maybe 125. But just your perspective on what ’27 looks like, recognizing it’s a transition year as you guys are working through the waterflood.
Richard A Jackson (President and CEO)
Yeah, no, appreciate it. I’ll start and then Ken can provide more detail, I think. One key point you mentioned I just want to reiterate: we’re moving into the capacity to make investments in things like the waterfloods, which are meaningful. We’ve had success; we continue development. An important investment capability that we now have as we’ve improved the balance sheet is these mid-cycle GOA waterfloods. And so part of that is spending the bulk of our capital, especially going into next year, around that project.
It has a bit of a delay in terms of production, but we think it’s really important as we think about this sustainable cash flow perspective that we’re putting together. But let me turn it over to Ken to walk through some of the moving parts.
Kenneth Dillon (Senior Vice President)
Good afternoon. Looking ahead to ’27, we’re currently optimizing the drilling schedule versus the available rig time. And as you said, we’re shifting capital to front-end-load the water injection wells; we’re sequencing the others to match the prioritized inventory, as well as looking at can we defer exploration and go into the following year in order to yield more development wells? Horn Mountain water injection wells will take four months to drill and complete and cost around $100 million each, so that gives you an idea of what the front end of the year looks like.
I think we have some opportunities, but overall I wouldn’t disagree with your assessment.
OPERATOR
Thank you. Our next question today comes from Doug Liggett with Wolfe Research. Please go ahead.
Doug Liggett (Analyst)
Thanks very much. Thanks, Richard and team. I appreciate you having me on. Richard, I guess these are kind of addendums to Neil’s questions, but my first one is on the $4 billion free cash flow improvement. I want to try and articulate this correctly. A decent part of that is the reduction in the decline curve, the 25 to the 20%. What I’m trying to figure out is once you achieve that towards the end of the decade, does that reduced sustaining capital translate to a lower absolute spending number or do you keep the capex at a level, for example, a pivot back to growth?
That’s kind of my first question. My second question is on what you just said about the dividend, because we know you have a penalty on redeeming the prefs early. You also have a penalty on the threshold for buybacks. What you don’t have a penalty on is your dividend. And I’m thinking back to the Steve Chazen school of dividend aristocracy. You’ve got the portfolio of a major, basically, but you don’t have the dividend of a major. And the scale of the cost cutting, the interest charges, the prefs, and so on.
I think back to Anadarko in 2021 with an 80% step change in the dividend. I’m wondering if that’s the kind of thing that’s on your mind about how you think about the disadvantages of pro-cyclical buybacks, the preference share redemption, and ultimately the capacity for a material step change in dividend. I hope that that makes some kind of sense, but those are my two questions. Thank you.
Richard A Jackson (President and CEO)
No, that’s great, Doug. I’ll start with the $4 billion and the pieces on sustaining capital. I think we really like the sustainable cash flow the way we put this together. And let me just break it down on a few moving parts in terms of cash from continuing to drive, obviously expenses, but also higher-margin production. And some of that’s even oilier production as we look at things like GOA or Powder River Basin or even our EOR. And so both of those are improving even with flat capital and flat production—that’s one component.
The other component is sustaining capital, as you mentioned, and two parts to that. One is capital efficiency. So this new well and facility cost improvement that we continue to drive—we’re able to deliver more with less. We’re actually dropping three rigs at the end of this year, adding 15 more wells online. We’ve just continued to be able to drive that—more productivity per dollar spent. And then the last piece, as you said and have helped us highlight, is really this decline rate.
And so the decline rate comes from projects like GOA waterfloods that we’ve been able to point out, but also these opportunities in EOR that really came about this year. So as we look to your last part of that question—really growth—the way we think about growth is, one, we can improve the sustainable cash flow, cash from operations minus sustaining capital, really without growth. So make that point. Two, growth for us will be—we call it measured and efficiency-led. The returns are obviously important. We need to maintain cost efficiency. And then the free cash flow timing as we put all these pieces together is really important.
So if growth is a part, one, it is likely efficiency-led. And if there’s more capital that goes there, it will be very measured, all the time making our sustaining cash flow better. So, let me jump to the dividend and buyback, and then, Sunil, if you’ve got anything, you can add to that. I think, again, back to key points—our cash flow priorities. One, the stronger balance sheet. And as we have improved our financial strength, it really provides opportunity for all of the above—operational efficiency through the cycle, but a broader return of capital. You’re right: dividend for us is really how we think about the fundamental starting point for return of capital in the business.
And it’s back to what is your cash from operations and your sustaining capital at 50. And so that today, with progress like our debt interest, provides quite a bit of room for that buybacks, you know, as we reach a net cash position, that becomes a part of our opportunity as well as we see dislocation, as we see in our share price. If we see the right macro condition longer term, we would like that to be sizable and more countercyclical, which is back to why we need such a strong balance sheet to accomplish that.
So let me just make sure Sunil gets any final points there too.
Sunil Mathew (Chief Financial Officer)
Hi, Doug. Like I mentioned in my prepared remarks, at $6 billion principal debt, our interest expense savings alone will be approximately $1 billion lower than 2025. And if you look at our current annual dividend payout run rate, it is around $1.1 billion. So our current annualized common dividend run rate compared to, say, the fourth quarter of last year, is higher by around $175 million, and that is primarily related to the two dividend increases we announced this year.
So adjusting for that dividend increase, interest savings alone will be around $825 million lower than 2025, which provides the opportunity for a sustainable and growing dividend. And we also, like Richard just walked through, have highlighted the operational efficiency improvements in our $4 billion cash flow plan, which is again going to further support a sustainable and growing dividend. So like you correctly summarized, we do have the depth and quality in our portfolio. We are building a very strong balance sheet. We have outlined our $4 billion annual sustainable cash flow improvement plan, which all leads to a sustainable and growing dividend.
So we’re just being measured and disciplined, but that is something we are thinking through, and at the right time we will be announcing the changes in the dividend. And the last thing I would say is, like Richard highlighted, a stronger balance sheet also provides the opportunity to do buybacks through the commodity cycles, which will be our preference after the redemption of the preferred. And until then, we’ll just be opportunistic in terms of share repurchase.
OPERATOR
Thank you. Our next question today comes from Betty Jiang with Barclays. Please go ahead.
Betty Jiang (Analyst)
Hi. Thank you for taking my question. I want to go to the Delaware CO2 offtake contract. Seems like that’s opening a new chapter for your EOR business. So just want to understand how you’re thinking about incorporating those volumes into your EOR portfolio once they come online. Are you more thinking about that as a lower cost replacement for the CO2 that you are already buying, or does that let you do more EOR and expand the opportunities potentially in the unconventional space?
And longer term, just given the size of the gas processing footprint in the Permian, how big could that CO2 supply become, and does that materially change the economics of your EOR projects?
Richard A Jackson (President and CEO)
Betty, thank you very much. Yeah, we’re excited about this step here. I think, just to frame a few of those points today, these deals we’re talking about are 2 million tons a year that we’re able to capture the CO2. Today, Oxy purchases about 12 billion tons a year. And so it’s a meaningful step, and I’ll get through kind of the market and opportunities in a moment. One thing to say is that it’s meaningful reduction in cost as we’re able to put these pieces together between the developers, obviously the gas processor, and then our ability to pay for the offtake.
And so about 30% of the cost of an EOR barrel is power and CO2. So when you’re talking to move 15%, or possibly even higher, that’s a pretty meaningful step change in the total spend per barrel. As we look at these EOR opportunities, the size of the prize—our team has put together a look and estimate about 50 million tons per year of CO2 from sources like this. The two most meaningful are gas processing, and the other I would highlight that we remain optimistic about is natural gas power generation. So we see about 10 million tons a year gas processing and over 15 million tons a year natural gas power generation. Obviously there’s been a lot of talk about that in the Permian.
Just for reference, 5 gigawatts of power generation basically replaces our CO2 purchases today. And so, again, pretty meaningful. In terms of where we go with the volumes, I think optionality is the word I would tell you. Being in the Delaware Basin—obviously great proximity to our own unconventional opportunities—but because of our CO2 infrastructure that we have, it’s also near pipelines and the ability to get it to our Central Basin Platform. So we’re very excited about this. The developers that we’re partnering with—we’re happy that they’re able to fund and build these.
And so it really is a type of partnership, capital-wide approach that we have intended for our CO2 sourcing. So appreciate the opportunity to talk through all that.
Betty Jiang (Analyst)
Thank you for the color. That seems like a big opportunity long term. And then for my follow-up, if I can go back to just 2027 and hoping to get more color on the oil trajectory into next year. There’s been quite a bit of noise in the back half of the year because of the GOA outages, and in the early part of the year you had the EOR divestiture, and there’s also activity shift between the PRB and the DJ in the Rockies. So can you just help us think through the oil trajectory into next year, and just high level, should we expect oil volumes to grow on average on a year-over-year basis?
Sunil Mathew (Chief Financial Officer)
Hi Betty, Sunil here. So like I mentioned again in my prepared remarks, with the 5.9 billion we expect relatively flat production on a BOE basis. But on an oil basis, at a high level we expect production to be flat to a slight increase. And if you look at some of the contributions from the different business units, Permian production is expected to grow modestly both on a BOE and oil basis. So it is basically building on the results and learnings from our 2026 program.
And we are grading our ’27 plan towards higher return opportunities and positioning us for modest production growth with strong capital efficiency. So like Richard said earlier, it is about doing more with less. In terms of Rockies production, we expect it to be flat on a BOE basis, but we expect growth in the oilier Powder Basin offsetting the decline in DJ. We already talked about Gulf of America. The teams are still optimizing the drilling program between development and exploration, and like Ken mentioned, the two injectors are going to be front-end loaded in our drilling program, so there could be some reduction in the Gulf of America production due to the timing of these injectors.
Compared to this year, the production could be lower. And with respect to international, the PSC impacts would largely impact the oil production in Oman and Algeria. So overall I would say the range is going to be largely driven by GOA and international.
OPERATOR
Thank you. Our next question today comes from Nitin Kumar with Mizuho. Please go ahead.
Nitin Kumar (Analyst)
Hi, good afternoon, Richard and Sunil. Thanks for the update on the advanced recovery. I’m going to actually go back to primary recovery for a minute. One of your peers has talked about the Barnett formation, and you highlight well costs that are quite a bit below what they’re seeing today. Just curious, what do you see as the opportunity in the Barnett and how does that fit into your overall development program?
Richard A Jackson (President and CEO)
Yeah, thanks for the question. We’ve been really pleased with the Barnett progress. As you know, we started several years ago really as part of our Ecopetrol JV. We were able to learn and appraise that opportunity. So we’ve had several years at it, which I think has helped us. I think we’ve got still about 30% of all the online wells, or wells that have been drilled in the Barnett, have been Oxy’s. I would say a few pieces to how we look at it, starting with the drilling costs where you went. I think we’ve been able to achieve more 10,000-foot laterals, and that’s really helped bring our drilling costs down. We’ve been really less than $750 a foot for drill, complete, and equip. We like to include that hookup component as well in our numbers, which has been very good and certainly quite a bit of improvement since 2025. But as importantly is the well performance, or even more important.
We look at our six-month oil per foot; we’ve been over 12 and a half there, which has been quite a bit better than industry. I think we’ve got more than 10 of the top 15 wells on that metric. So that well performance we’ve been very focused on. I’d say the one thing we did this year is be able to do a bit more appraisal. So we’ve gone to sort of delineate some of the areas for us; that means really on the eastern side of our position. And so we’ve been able to learn that. We’ll be coming back into the core for the remaining wells this year and into next year, so we expect these top performers to continue to improve. But overall, very pleased with that. It’s a big part of the Midland Basin and we’re excited about our Barnett opportunities.
Nitin Kumar (Analyst)
Great, thanks for the color, Richard. And I want to maybe touch on Stratos. We haven’t talked about it yet, but you mentioned in the slides that there was a little bit of an incremental cost for some repairs. But you expect that project to be starting up at the end of the year. Given how the market for carbon credits has shifted, just if you could maybe give us a reminder of what is the— I know the capex rolls off next year, but what is the EBITDA opportunity?
Or do you see that as sort of accomplishing this new CO2 offtake that you just signed?
Kenneth Dillon (Senior Vice President)
Good afternoon, it’s Ken here. Yeah, as you said, we have had cost increases during the life of the project. Around 60% came from technology and operational improvements and phasing. The remainder is made up mainly of inflation, productivity, and QA/QC during the life of the project. Spend next year will be minimal. In terms of the impact on the levelized cost of capture, it’s about 10%. Because of the leverage difference between capex and opex on the project, we can see potential ways to offset some of those opex elements following startup, and we have some operational milestones to track those.
Yeah, and I’ll just add as we think about economics and maybe the market and even how it compares to these CO2 supply agreements we just had with the gas processing. I think start where Ken did, I think two key drivers, one starting clearly opex. And so as we look at the opportunity for opex, we feel like that’s well within our capability to think about a 10-plus percent improvement in opex, which will drive more than the capital that we’ve seen.
And honestly it’s just as important for the technology longer term to drive that component of it. So we’ll be very focused on opex. I think the outlook for EBITDA remains the same. Obviously that opex will help improve that. So next year will be a ramp-up, and then we pointed to project EBITDA in 2028 of 90 to 130 million dollars. So we remain on track for that. The third part is how to further improve that would be the market, and I think unique for direct air capture is really that market component where your atmospheric CO2 is at a premium. And so we think about access to things like sustainable aviation fuel markets where this is quite a bit lower cost both from a CDR credit, and at Occidental Petroleum we really see that enhanced oil recovery would fit in that sustainable aviation fuel basket. And so both of those would support a premium for direct air capture.
What we can control is bringing the cost down, and we still see tremendous improvement. And as we get this operational, we hope to point to more where we can drive significantly the cost of this down to get to the CO2 price that can fit into EOR as we gain more access into those premium markets. So hopefully that helps tie the pieces together. But the first step is coming online and really delivering against the customer base that we have today to deliver that EBITDA.
OPERATOR
Thank you. Our next question today comes from James West at Melius Research. Please go ahead.
James West (Analyst)
Hey guys, wanted to touch on the dividend again and just curious if you have some type of framework in place. I know you don’t want to get ahead of your skis, you don’t want to grow it too fast, you want it to be durable. But is there some way we can think about what to expect as you transition into this dividend growth story?
Richard A Jackson (President and CEO)
Yeah, I appreciate the question to walk through that because that is a really important foundation for how we’re trying to build the business. So we think about this sustainable cash flow at $50. We look at our cash from operations, we look at our sustaining capital at $50, and we believe that cash flow is what we point to for dividend capability. I would say in the near term, we’ve been working on the balance sheet, which we feel like, again, longer term does things for operational continuity and broader return of capital, things like share repurchases.
But ultimately we will always point to that $50 sustainable cash flow for how we think about a dividend. And for us in the business, and especially in operations, these are very clear drivers for our operational teams: capital efficiency, base decline, lower LOE. And all of those, as we mark progress, will be in direct correlation to what we can do with the dividend. And obviously debt interest is a big part of it this year.
James West (Analyst)
Okay, I think that’s fairly clear, Richard. Thank you for that. And then maybe just a quick follow-up. You mentioned you’ve got AI on, I think, 68% or so of the wells watching the recoveries. And I’m curious if you could dive a little more deep or give us a little more detail there on: Are you running some autonomous operations? Is it acting as just a data context for your engineers? How are you using that AI?
Richard A Jackson (President and CEO)
Yeah, excited about that. It’s moved quick for us in a good way, especially around our production operations. So a couple pieces beyond what I was able to say in the prepared remarks. You’re right, 9,000 wells are under AI surveillance today. It does two things. One helps engineers—the AI can work at night—and so it helps accelerate the engineers’ access to what could be the dysfunctions, whether that’s downhole or even on surface with things like compression, to optimize.
The subset of that that’s autonomous is about 50%. So, meaningfully, we have quite a bit of production, especially in the Delaware Basin, that operates autonomously—about 450,000 barrels a day. And what that’s doing is, as we again see dysfunctions or opportunities in things like our gas-lift system, you’re able to reroute or optimize gas downhole across a larger network. So these are quite a few wells that are tied into an individual network that you’re able to optimize.
Longer term, drilling and completions are squarely in scope. I think we’ll continue to drive up both the surveillance and the autonomous nature of our system. And then maybe on the front end is seismic. In the Gulf of America—this may be interesting or unique to Oxy—we’re not only using wells to improve our seismic, say sub-salt seismic; we’ve been able to use over 3,000 wells to help better generally characterize the subsurface. And that can help on things like waterfloods, really optimizing placement and management of the waterflood.
So lots of opportunity with AI. Ken’s been pretty focused on that as well, so I’ll make sure if he has anything else to add.
Kenneth Dillon (Senior Vice President)
Just building on what Richard said, on the subsurface side in Oman, for example, we inject 600,000 barrels a day of steam. All of that is now optimized—injection at every well, every location, by every pattern. So we see significant benefits there. In terms of operations, the teams here have done an amazing job at reducing failure frequency on every type of artificial lift. We’re now at our lowest failure rates in our history. And then the last thing is maintenance analysis.
If you look at GOA, we’ve got 155 large rotating equipment elements offshore. Fifty-five percent of our unplanned failures relate to seawater lift pumps. That analysis was done in about an hour. So if we fix one bearing, we then reduce our unplanned failures by 55%. It’s shocking the speed that this is flowing through each department.
OPERATOR
Thank you. And our next question today comes from Arun Jayaram with JPMorgan Securities. Please go ahead.
Arun Jayaram (Analyst)
Yeah, good afternoon. I wanted to get your thoughts on how you’re thinking about the exploration portfolio. We noted that you guys have contracted a rig to do some work in Peru, maybe a couple wells. I’d love to hear broadly how you’re thinking about exploration as we think about 2027.
Kenneth Dillon (Senior Vice President)
Yeah. As you look at the offshore exploration you mentioned, with our partnerships, we have three modest-investment exploration opportunities included in our capital plans. These provide exposure to mean net unrisked target volumes of greater than 2 billion BOE, which, if successful, would be in the post-2030 development timeframe with partners, which we could adjust. That includes Trinidad and Tobago with Exxon, the Trujillo Basin in Peru, as you mentioned, and then Komodo in Colombia, where we’ve made some permitting progress recently and where we’ve operated before.
Maybe I’ll just add one piece on that. I think the teams have done a great job between exploration and development, not just thinking about the finding cost and the timing. I think we’ve been smart thinking longer term about finding and development costs, making sure it all fits our sustainable cash flow plan and then, as we think about 2030, making sure it all fits to improve. But we’ve got a great pipeline, teams have done a great job. So it’ll be exciting as we’re able to pursue those in our future.
Arun Jayaram (Analyst)
Great, thank you for that. I just had one follow-up on the cash flow statement, maybe for Sunil. Sunil, in the discontinued ops line, you’ve had some outflows, I think, related to OxyChem and taxes. Can you just elaborate on that? It was about 450 million in the quarter and about 1.4 billion year to date.
Sunil Mathew (Chief Financial Officer)
Hi, Arun. So with respect to the Q3 455 million, around 415 million is related to tax, and the balance 40 or 45 million is related to environmental and transaction costs. And on a year-to-date basis, of the 1.4 billion, around 1.2 billion is related to tax, and the remaining is a combination again of environmental and transaction costs.
OPERATOR
Thank you. And this concludes our question and answer session. I’d like to turn the conference back over to Richard Jackson for any closing remarks.
Richard A Jackson (President and CEO)
Okay, thank you again, everyone. We really appreciate the questions and your time today. Please have a good day.
OPERATOR
Thank you. The conference has now concluded, and we thank you all for attending today’s presentation. You may now disconnect your lines and have a wonderful day.
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