Good morning. My name is Katie, and I will be your conference facilitator today. Welcome to Chevron's Third Quarter 2026 Earnings Conference Call.
At this time, all participants are in a listen-only mode. After the speaker's remarks, there will be a question-and-answer session, and instructions will be given at that time. If anyone requires assistance during the conference call, please press star then zero on your touch-tone telephone.
As a reminder, this conference call is being recorded. I will now turn the conference call over to the Head of Investor Relations of Chevron Corporation, Jeanine Wai. Please go ahead.
Thank you, Katie. Welcome to Chevron's Third Quarter 2026 Earnings Conference Call and Webcast. I'm Jeanine Wai, Head of Investor Relations.
Our Chairman and CEO, Mike Wirth, Vice Chairman, Mark Nelson, and CFO, Eimear Bonner, are all on the call with me today. We'll refer to the slides and prepared remarks that are available on chevron.com. Before we begin, please be reminded that this presentation contains estimates, projections, and other forward-looking statements.
A reconciliation of non-GAAP measures can be found in the appendix of this presentation. Please review the cautionary statement and additional information presented on slide two. I'll now turn it over to Mike.
Thanks, Jeanine. Chevron delivered another quarter of outstanding operational performance and disciplined execution, reliably supplying the energy the world needs. In the U.S., upstream production was more than 2 MMbpd for the fifth consecutive quarter.
We achieved record crude throughput in our refining system, helping meet demand in supply-constrained markets. We also continued investing to develop future energy supply. We announced a discovery in Angola within tieback range of Chevron-operated facilities, providing an opportunity for short-cycle, capital-efficient development.
Our joint venture with Bunge completed commissioning of a Louisiana oilseed processing plant on schedule, providing additional feedstock for Chevron's leading U.S. biofuels business. We expanded our acreage and established new fiscal terms in Venezuela, and we recently announced an expected 50% reduction in Bakken midstream tariffs that expands economic inventory and competitiveness. Chevron is well-positioned to deliver more energy today and well into the future.
Venezuela will be part of that story, where we have deep on-the-ground expertise built over our 100-year history there. With new fiscal terms, Venezuela is now more competitive within our portfolio and immediately accretive and free cash flow positive. Last month, we announced plans to double production for our three joint ventures to roughly 600,000 bpd, all on primary recovery, by 2031.
This development program will be self-funding and could extend further into the 2030s, underpinned by billions of barrels of resource. Total costs are expected to be under $20 per barrel, with competitive investment returns, and no major upgrades are needed, as infrastructure has been well-maintained. Chevron markets 100% of the crude from the three ventures, with the majority going to U.S. refineries, including Pascagoula and El Segundo, adding to domestic product supply.
We'll look to capture additional value as we optimize product flows across our system. We're on track to reach around 300,000 of gross production by year-end, up 20% over the last 12 months. Now I'll turn it over to Mark to discuss our operational achievements.
Mark Nelson
EVP, Downstream & Chemicals
Thanks, Mike. Our strong operational performance is driven by a relentless focus on safe execution, reliability, cost, and technology. At around 4 MMbpd, improvements in our base business create meaningful value.
In Shale & Tight, we achieved first-quartile reliability in the DJ Basin during the third quarter by applying AI to anticipate and minimize downtime and scaling learnings from the Permian, reducing loss production events by 50%. Advanced Chemicals continue to deliver strong results in the Permian, increasing cumulative oil equivalent production by up to 23% in the first 12 months. We also delivered strong performance in other parts of upstream, including record quarterly production in the Eastern Mediterranean as the Tamar Optimization Project and Leviathan Third Gathering Line ramped quickly.
Reliability in Australia continues to be strong, where predictive maintenance, centralized data-driven decision-making, and AI help maximize LNG supply into a tight market. In downstream, efficient turnarounds and the flexibility to respond to market conditions are essential to meet customer needs. More than 80% of Chevron's U.S. refinery turnarounds over the last two years were completed with first-quartile duration.
We have peer-leading complexity, and we're deploying a proprietary catalyst, increasing distillate yields by more than 10% at our largest U.S. refineries. We're also adding supply by increasing capacity at existing production facilities and refineries through highly capital-efficient expansion. In upstream, debottlenecking projects have recently added capacity of more than 85,000 bpd.
We announced a 20% capacity increase in TCO's third-generation plant, taking total processing capacity to slightly over 1 MMbpd. At Ballymore, a 7% increase in capacity contributed to record deepwater production in the Gulf of America. At Anchor, facility capacity has increased 33%, or 25,000 bpd, which should benefit new wells coming online over the next year.
We've done the same thing in refining, contributing to record quarterly U.S. crude throughput at a time when the market needs it. At Pasadena, we accelerated debottlenecking to increase refinery capacity by approximately 15% at nominal cost. We'll continue to pursue additional low-cost debottlenecking projects where practical, including at Pascagoula, where we expect to increase refining capacity by another 7% by 2030.
In exploration, our new operating model centralizes expertise, applies one global standard to rank and select opportunities, and drives faster decisions. Together with new technology and leadership, this is reshaping our portfolio and changing outcomes. We've added 22 million acres over the last two years, doubling our footprint.
This includes 12 new basins with a focus on both sides of the South Atlantic Margin and the Eastern Mediterranean. AI is changing what we see subsurface and how quickly we see it. One of our proprietary AI solutions, ApEx, draws on four petabytes of data and 100 years of company knowledge, now pulling together basin information in hours, not months.
ScoutAI, now deployed in 10 new basins, builds basin assessments in hours, not weeks. Our latest technologies, combined with AI-assisted interpretation, provide sharper subsurface imaging to identify and high-grade new prospects with greater conviction. AI pattern recognition has identified more than 150 leads in our Gulf of America portfolio alone, with 16 prospects moving into evaluation.
All of this is leading to better outcomes. We've made 15 infrastructure-led discoveries in two years at a success rate of 40%, above the industry average. Real-time optimization using AI continuously monitors drilling conditions, recommends actions to reduce non-productive time, and maximizes performance.
With 30 net new prospects identified, we're increasing exploration spend by 50% relative to 2025 and are focused on executing with capital and cost discipline. I'll now turn it over to Eimear to discuss the financial results.
Thanks, Mark. For the third quarter, Chevron reported earnings of $9.9 billion, or $5.06 per share. Adjusted earnings were $10.4 billion, or $5.28 per share.
Cash flow from operations, excluding working capital, was $16.6 billion. Organic CapEx was $3.9 billion in the quarter. In line with historical trends, we expect fourth-quarter CapEx to increase while still finishing the year at the low end of our annual CapEx guidance.
Chevron's net debt coverage ratio improved in the quarter as a result of the strong cash generation. Adjusted third-quarter earnings were $1.6 billion lower versus last quarter. Adjusted upstream earnings decreased due to lower realizations, lower liftings, and unfavorable timing effects, and were partly offset by lower DD&A and tax effects.
Adjusted downstream earnings increased primarily due to higher refining margins and volumes, more than offsetting unfavorable timing effects. Chevron generated $16.6 billion of cash flow from operations, excluding working capital, and $14.2 billion of adjusted free cash flow in the quarter. We reduced debt by more than $3 billion and grew cash by more than $4 billion, further strengthening our balance sheet, enhancing our ability to fund the long-term investments needed to reliably deliver energy long into the future.
Net debt to CFFO at the end of the quarter was 0.4 times. Working capital was negatively impacted by sharp commodity prices increases late in the quarter. Looking forward, consistent with historical trends, we anticipate additional timing effects when prices are rising and unwinds when prices are falling.
Third-quarter production was nearly 4 MMbpd despite anticipated entitlement impacts and planned turnarounds, highlighting sustained operating performance across the portfolio. This includes one month of production from our Venezuela joint ventures following the change to equity accounting. We delivered a new quarterly natural gas production record, producing more than 9 billion cu ft per day, led by strong performance in Australia and the Eastern Mediterranean.
In addition, other core assets achieved new performance levels. In the U.S. Gulf of America, they set a new quarterly deepwater production record. The Permian recorded sixth consecutive quarter above 1 MMbpd, and TCO has been operating near full rates over the last several months.
In closing, Chevron delivered another quarter of strong performance, and yet we're never satisfied. Execution is excellent across the base business and projects, and we're relentlessly pursuing opportunities to safely improve further. Technology is an important part of that.
Our proprietary capabilities are helping increase reservoir recoveries and get more from every barrel we process. 2026 is also proving to be an inflection year for AI, with more than $100 million in value capture to date, with much more building quickly. At the same time, the strength of our partnerships is creating opportunities for the next decade. We see that in Venezuela, in our efforts to extend our concession into Kazakhstan, and as we pursue growth opportunities in Iraq.
Underpinning all of this is an unwavering commitment to consistent financial priorities and capital and cost discipline. We're delivering strong performance today while stacking competitive growth options to reliably deliver the energy the world demands for decades to come. I hand it back to Jeanine.
Okay. Thank you, Eimear. That concludes our prepared remarks.
Additional guidance can be found in the appendix to this presentation, as well as on the slides and other information posted on chevron.com. We're now ready to take your questions. We ask that you please limit yourself to one question, and we'll do our best to get all of your questions answered.
Katie, please open the lines.
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Our first question comes from Arun Jayaram with JPMorgan.
Yeah, good morning. Appreciate the color on your opportunity set in Venezuela as an early mover advantage. I was wondering if you could maybe touch a little bit on the cost structure.
I know that when you put that out in September, it was probably $10 a barrel lower than we're thinking. Maybe you could also elaborate on how you're managing some of the above-ground risks as we think about restarting activity in Venezuela.
Yeah. Let me comment on the risk question, and then maybe I'll ask Eimear to make some comments on the cost structure. Arun, we manage risk around the world as part of our everyday business.
One of the ways we do that is by having strong terms, and that gives us the ability to generate strong financial returns. Certainly, we've seen the terms on offer in Venezuela become much more competitive. We also have provisions in this contract relative to stability clauses, international arbitration, et cetera, which are as good as we see anywhere in the world.
Now, one of the most important ways to address risk is not by relying on contracts, but it's by doing what you say you're going to do. That means you contribute to the economy, you meet your obligations, you treat people right, and you're a positive force in society and in the country. In our 100-year history in Venezuela, I'm very proud of the way our company has contributed through jobs, investments in communities, generating a lot of tax revenue, bringing our values and focus on safety and reliability.
To me, the best way to manage those risks is to have support of the people in the country, and that leads to an environment where you can resolve any differences that may emerge. The last thing that I'll say, or maybe two last things that are different today than they have been historically, is, number one, we are lifting all of the oil. It's not being marketed by PDVSA, it's being marketed by us.
We then control the flow of the revenue back into the country and the disbursement of taxes and royalties that are legally obligated, the payment of costs, et cetera. The second thing is, we're covering the last bit of debt that has accrued through loans that were made long ago. As we go forward, this will all be self-funding.
The capital will be generated through the revenues in the venture, and we won't be exposing additional capital investment. So it'll be recovered quickly. It's a factory-type drilling program that has analogs to other things we do elsewhere in the world, and we can manage the pace of activity up or down as market conditions call for it.
So, it's a very different set of dynamics than we've historically had in Venezuela. We're also very pleased with the cost structure there. I'll let Eimear talk a little bit about the $20 number we put out there today.
Yeah, thanks, Mike. The cost structure's really competitive, so total cost less than $20 a barrel. So think of that as CapEx and OpEx.
As Mike said, this is a factory-like operation, so we'll continue to learn, continue to become more efficient over time. So this is low cost, this is a high return, very competitive within our portfolio. Another thing I would mention is we're not anticipating that we'll have any major additional infrastructure spend as we double production between 300,000 and 600,000 through the end of the decade.
So we have the infrastructure we need, and as we build out and as we grow, it'll be more, get small capital versus anything major. Those are the key things. Thanks.
Thank you. We'll take our next question from Devin McDermott with Morgan Stanley.
Hey, good morning. Thanks for taking my question.
Hey, good morning, Mike. I wanted to check in on the TCO concession extension progress. There have been some media reports recently making statements around some of the government asks, includes things like one-time payments or working interest adjustments.
I understand you might not be able to talk specifics or comment on that media speculation, but I was hoping you could talk at a higher level on progress, and then you can share on how the dialogue's been going, any thoughts on timelines. I guess the key question is, based on your learnings from the process so far, what does an ideal win-win outcome look like in your view?
Yeah, thanks, Devin. You're right, I'm not going to comment on media reports or specifics, but I can talk about the process. We continue to make good progress, and I continue to be very encouraged.
The discussions began a little bit over one year ago. We've had technical, commercial, and legal teams meeting on a regular cycle. I've been in contact with the president multiple times during this period of time to be sure that we stay aligned.
All the TCO partners have been at the table and have been actively participating. All the relevant government officials have been in all these meetings and has ensured good alignment. The list of issues has narrowed really to what I'd call the fundamental core issues, and we're focused on working those.
I think they're very reasonable issues to be on the table. They're the things you would expect here 35 or so years after the initial deal was put together, and we're working our way through those. This is a large, complex contract and obviously a very important asset to the republic.
I don't see any red flags, and so we continue to be pleased. I'll give you more meaningful updates as we have milestones to report. In terms of what good looks like, we need to have something that is, in today's world, I think, competitive for the republic.
They want to see their large resource assets stewarded responsibly, which is something we're very proud to have done for our years there. The work on the technical side of this is to have a development plan that we're very aligned around going forward as we continue to steward this massive resource position for decades into the future. For the partners, we need something that is a competitive value proposition, and that means that for the capital we have already invested and the capital we would invest going forward, that we can get a competitive return.
Every one of the partners has alternatives in their portfolios, and this needs to be competitive, as we have discussed with Venezuela and other assets. I think each side understands what the other side is looking to accomplish, and we are working together to land this in a place that all the parties feel that this is an agreement that meets their needs. More to follow as we reach significant milestones.
We will take our next question from Neil Mehta with Goldman Sachs.
Yeah. Good morning, Mike and team. Just want your perspective on the Bakken since the last time we connected.
You did restructure some of the Hess Midstream contracts, so just trying to think about the financial impact, but maybe just stepping back, big picture, now that you have had some time with the Bakken, do you view that asset as core or not?
Mark Nelson
EVP, Downstream & Chemicals
Hey, thanks, Neil. This is Mark. I will give the front end of this, and then we will have Eimear comment on some of the economics.
Our operational activities that we have been working on in regard to improvements day-to-day and this action with Hess Midstream are all about enhancing value and increasing flexibility. As Mike mentioned in his comments, the 50% reduction in tariff, it quite frankly makes the Bakken stronger. It improves upstream returns, it expands economic inventory, and it, maybe most importantly, increases operational flexibility.
This is what excites me the most, because it will allow us to evaluate the full potential of the basin. We have already begun to put in place more optimized development plans that build on the ongoing operational improvements that we have been building in over time. We'll move from three rigs to two rigs at year-end while sustaining 180,000 bpd of oil equivalent production, again, building on the operational improvements that we've made.
You should expect to see more long laterals with these changes. We'll go from 60% long laterals this year to over 85% in 2027, and we'll begin to lean into our advanced chemicals opportunity. I'm encouraged by what I'm seeing today and the future potential.
Eimear, maybe you can help on the economics.
Yeah, thanks, Mark. Hi, Neil. Yeah, we expect to realize several financial benefits with this, in addition to simplifying the reporting structure, as you mentioned.
Overall, it increases our corporate ROCE by 0.5%, deconsolidates $3.7 billion of debt, and delivers incremental recurring earnings. It'll close at the end of the fourth quarter. We're still on track, and when it closes, we'll report a one-time non-cash after-tax loss of $3 billion-$4 billion.
We will treat that as a special item, and it just reflects the accounting treatment on this deconsolidation, not any deal economics. As we look to 2027, we'll see an immediate improvement in Bakken upstream earnings and cash flow. It'll be partly offset by some cash outflows, primarily related to taxes.
We're really excited about this, proud of how the operational teams are working together in our centralized Shale & Tight organization, of which Bakken's now a part of that, and this transaction just takes it a step further and helps us unlock more financial upside. Thanks for the question.
We'll take our next question from Neal Dingmann with William Blair.
Morning. Thanks for the time. My question is on capital allocation, Mike, specifically.
Obviously, the balance sheet now is even what I call beyond pristine. When you look forward, you tend to have numerous exploration opportunities, and I just think the opportunities, both organically and externally, are just broad. I guess my question is, given how low the balance sheet is now, is your thoughts about next year, if you could change in the way of allocation.
Neal, I'll take this one. The balance sheet has strengthened over the course of the year as a function of the outstanding operational performance that we've seen across the organization. Given the fact that the market dynamics are still very volatile, in third quarter alone, a $64 intra-quarter spread.
We saw prices as low as $68, as high as $132 a barrel. So we're not changing anything in the short term given that volatility. Our capital allocation framework and our financial priorities are long-standing, and they've been in place for decades, and over high prices and low price environments, they've really stood us well.
So no change to capital allocation. Maybe just recap, the first priority within that is to grow the dividend consistently. We've done that for 39 consecutive years.
We'll continue to do that. That is a commitment we have to shareholders. The second is to invest capital efficiently.
We have a capital program that's underway, and we are trending towards the low end of the guidance this year. We're investing in the business today, and that's also enabling us to invest in the future. So no change there.
In fact, we're seeing in places like the Permian that we can deliver on the goals there with less capital. The third is to maintain a strong balance sheet so that the cash generation and the coverage ratios that you saw in the material today really show how strong that is. And the fourth is repurchase shares through the cycle, and we have maintained our rate of $2.5 billion-$3 billion of buybacks, and we intend to be buying back shares within that range.
Overall, our track record of using this framework, whether it be dividend growth consistency or buybacks through the cycle, 19 of the last 23 years, it's held up very well. So we're on track with our 2030 plan that we guided in the investor day, and we don't see any major challenges there.
Neal, welcome back, and we will give you some additional color on the 2027 capital program in December after we meet with our board.
Thank you. We will take our next question from John Royall with Piper Sandler. John Royall Senior Research Analyst and Head of Integrated Oils, Refining, and E&P Equity Research Hi.
Good morning. Thanks for taking my question. I wanted to see if I could dig in a little on the comment Mark made about increasing distillate yields at the refineries.
If you could just provide a little detail around what you have been doing with your catalyst to boost your output on the diesel side, and maybe just if you could talk more broadly about any other initiatives you are looking at in refining and just other levers that maybe you could pull that are similar to this lever with the catalyst and distillate yields.
Mark Nelson
EVP, Downstream & Chemicals
Yeah. Thanks, John. Maybe stepping back, I couldn't be more proud of our manufacturing team with another record crude throughput, strong reliability, something we have been working on for a while, our top quartile duration of turnarounds, and then these capital efficiency bottlenecking actions.
There is a lot of strong momentum, and what is interesting in the manufacturing business is that sometimes repeatability is the best equation, and so we want more of that going forward. Specifically to the change that we made with our catalyst, I think you know, we have got peer-leading complexity, and that means we have got a high proportion of hydrocracking. So we were able to, after a little bit of an adjustment, deploy this proprietary catalyst into our largest refineries, and it immediately, with some adjustments to cut points, allowed us to increase distillate production by 10%.
For our large refineries, our third quarter distillate yield in the U.S. was 46%, and across our global portfolio was even higher than that. In fact, Pascagoula hit a diesel production record, at least over the last three or four years, this quarter as well. I think what we need going forward to meet customer needs is more of the same.
In some cases, that might be viewed as boring. I view that as exciting. We're bringing AI into our reliability equation, where we're helping to predict where risks occur using 100 years of data.
That's helping us continue our reliability string. We're also bringing AI into our yield equation, where we're looking more quickly at how we can produce more of what customers need today. I think we mentioned this in our prepared remarks, for Pascagoula, over the next two turnaround cycles, we'll increase capacity there by another 7%.
More of the same to come, and couldn't be more proud of the team. Thanks for the question, John.
We will take our next question from James West with Melius Research.
Hey. Good morning, everyone. I wanted to touch on AI a little bit further.
I know Mark's made a couple comments on it, but Chevron was really early in the adoption and implementation of AI, not just amongst the super majors, but the oil and gas industry broadly. I'd love to hear how you're using this at both the enterprise level, and then maybe some further context in your exploration programs.
Okay. I'll get us started across the enterprise. We are sitting on both sides of the AI equation.
On one side, leveraging AI to lead and drive performance, and on the other side, delivering the energy that will power AI. We've got our focus on three main things. The business, using AI to make better decisions, operate more efficiently, to helping meet that growing energy needs.
The third area is really equipping everyone in the organization with the capabilities that they need. Let me give you a couple of examples, because we have captured real value this year, more than $100 million year to date, and we expect, obviously, that to increase significantly as we scale. Maybe Shale & Tight is the one to mention before I hand over to Mark to cover exploration.
But we're using an AI production engineering, kind of an agentic assistant to help us optimize production on an ongoing basis. We've got this deployed in Permian, in Bakken, and in our PZ assets. This is something that we have built in-house that is 24/7 optimizing the production from our wells.
Another example would be how we're using AI to help us with designing wells and scoping capital projects. There, we've got some proprietary tools that are in development, and we're testing them at a really early stage. On the operations and commercial side, human agent teams helping us with turnaround and refinery planning.
Mark, maybe on the exploration side, you can cover it.
Mark Nelson
EVP, Downstream & Chemicals
Yeah, thanks, Eimear. James, quite frankly, I think it's reshaping our portfolio and exploration at a large scale, and it's delivering higher confidence prospects at pace. The way I think about it is our goal is to have rapid access to data, reduce cycle time, and then increased success rates.
Back in our investor day, we shared one of the first things we did, which was the system called ApEx, which allows us to get our hands on data more quickly for better and faster decision. This is that 100 years of data at our fingertips. The next thing that we did was create something called ScoutAI, which allows us to essentially do a deep basin assessment in hours, and we're applying that in 10 new basins as we speak.
When you combine those tools along with our spatial high-grading, elastic waveform inversion, and ocean bottom node data that we have available, we are coming up with new prospects. I mentioned in my prepared remarks about the Gulf of America, where we created over 150 leads and then essentially added 16 to our list to evaluate. We're incorporating this throughout the exploration process, including real-time drilling optimization.
It's touching every part of the exploration value chain, and I expect the impact just to continue to grow. Thanks for your question.
We will take our next question from Biraj Borkhataria with RBC.
Hi there. Thanks for the presentation and taking my question. I wanted to go to slide six, which I thought was very interesting.
We obviously spend a lot of time looking at major projects, but these barrels are some of the highest value-add barrels that you have. I was wondering if you could talk about the potential to do something like this in your LNG portfolio, and particularly in Australia. Are there any sort of active debottlenecking projects that are ongoing, and where are we now relative to nameplate, and what's the potential there?
Thank you.
Mark Nelson
EVP, Downstream & Chemicals
Yeah. Thanks, Biraj. I would view debottlenecking as a mindset, and it just builds on our mindset of capital discipline.
I would say historically, manufacturing facilities like refineries were somewhat accustomed to this, but given some of the operating model changes that we've made in centralizing project activity, major capital projects as well as small projects, is creating this opportunity to see across the portfolio where we have these opportunities. We've mentioned some of the examples in the upstream from the 20% increase at FGP to the 7% increase at Ballymore and the 33% increase at Anchor. We are already above nameplate at Gorgon and Wheatstone today, and I see more potential for that.
What excites me even more than just that potential debottlenecking that can exist there, it's the reliability. With the world-class reliability we have in Gorgon and Wheatstone, allows the customers to get what they need. Having backfill projects, highly competitive backfill projects for decades into the future allows us to continue to leverage that.
So I see both things working together. Continued reliability, potential for capital-efficient expanded capacity, and backfill projects will help us do what we need to do. I think part of that led to our record production in the third quarter for the combined assets.
So, more to come. Thanks, Biraj.
Yeah. Biraj, maybe offline, Jeanine can follow up with you. We've done a lot of debottlenecking already at both Gorgon and Wheatstone.
I think we've talked about that on prior calls. We can share that information with you so you can see what's already been done there, which is a really good story, just Mark's just building on.
Thank you. We'll take our next question from Jean Ann Salisbury with Bank of America.
Hi, good morning. If permits for behind-the-meter projects in the U.S. become harder to get, is there more value in already permitted sites like Project Kilby? I guess the related question, how large could Project Kilby get, and what are the gating factors to grow them in your mind?
Hey, Jean Ann. Yeah, we're really excited about Kilby. It's a great project, 2.67 GW of power in West Texas with strong partners.
We signed a 20-year PPA with Microsoft, AAA quality customer, as you know, that really leverages our strength. From the very beginning, we designed our solution to kind of consider some of the concerns that are being expressed in terms of the grid. This is a behind-the-meter power project.
It won't put any pressure on the grid in the short term, won't raise prices. It's using non-potable water. That's why Governor Abbott on the 6th of August announced that it complies with the standards.
Right now, we do have room to expand. We could expand this from single cycle to combined cycle. It will all depend on additional permits beyond the permits, obviously, that we are working through the system for Kilby as part of our FID decision.
It is going to come down to subject to permitting. Overall, I would just say we are working towards our FID. We have our EPC contract that we are finalizing.
We are working through the permit process. We have to secure our financing, but we are on track with Kilby to have first power in 2028 and full energization in 2031.
We will take our next question from Sam Margolin with Wells Fargo.
Hello. Thanks for taking the question. Maybe just circling back to Venezuela and the broader resource opportunity.
I think one of the things that stands out about Venezuela is just the pace with which the business plan came together. You were able to, in a matter of months, commit a significant development to the resource owner. Globally, it does seem like there is a lot of kind of mega resources or resource whales that are more willing to accept foreign investment and partnership than in the past.
The question is if the process with Venezuela is representative of maybe what your capabilities are globally and if other resource owners are paying attention and if you think there is a transferable opportunity with the process.
Yeah. It is an interesting question, Sam. I appreciate your comments about how quickly we were able to reach a development plan and alignment with the government of Venezuela.
As an incumbent on the ground, as the only incumbent on the ground, we definitely have an advantage in terms of our understanding of the geology, the infrastructure. We have a very talented workforce. We have the service providers that are prepared to ramp up with us, et cetera.
It does have, as I mentioned, parallels with other factory development campaigns that we prosecute around the world. I will go to Iraq as maybe an analog, as you talk about large resource holders and willingness and an interest in bringing in new investment. I mentioned already that the terms in Iraq are more attractive than what we have historically seen there.
They are, right now at least, whereas we are working through the negotiation, they look very competitive. We are working on a development plan there in concert with the ministry and have a good line on that. I think it will have things in common with Venezuela in terms of it will be primarily drilling.
There may be some infrastructure work, but I think that that will be modest and manageable as opposed to a major CapEx project. The resource depth there is significant, and there are good exploration prospects that would come along with this deal. I have mentioned on prior calls that we are in discussions with other governments, a number of them in the Middle East, that are also interested in that kind of a proposition.
We have been, I think Eimear mentioned today, stacking growth options, very active in business development, very active in exploration with some success there, and addressing the longer-term growth outlook post-2030 with a very deep set of resource opportunities that have longevity, that have attractive break-even costs, attractive financial returns, and working to line those up so that we can pick and choose amongst the best of those and allocate capital to continue to supply this energy that the world is going to need well into the future. So, stay tuned as we bring things to a point where we can be more specific, as we were today about Venezuela. We will lay that out for you.
We will take our next question from Doug Leggate with Wolfe Research.
Oh, hi, everyone. Mike, thanks for having me on. I wonder if I could.
There has obviously been a lot of chatter by the government, the U.S. government, about incentives for drilling and so on. I am wondering if we look back to when you had your long-term growth trajectory in the Permian, you slowed that down after the Hess deal, and free cash flow was a priority and so on. I guess my question is, whether organically or, given where your share price is, inorganically, what would it take for you to go back to growth in the Permian beyond your current plan?
Well, we had signaled the intent to bring the Permian to a plateau in kind of the middle of the last decade, to be honest.
When we were at pretty modest production levels. As we reached and surpassed 1 MMbpd, we turned to managing that plateau, which will last not only the end of this decade, but the end of the next, and I expect well beyond that as we apply more technology to this enormous resource base. Mark mentioned in his comments today the progress we're seeing with some advanced chemicals that are helping us improve recoveries.
We've got a next generation of that chemistry that's moving out into field pilots, which we are optimistic may prove even more successful in terms of improving production outcomes and adding value. We continue to look at other technologies related to drilling, stimulation of the reservoir, and different types of fracturing technologies, all of which will provide optionality into the future. What they can do is they can extend the economic life of the plateau.
They can make it economic to grow to a higher level. They can take benches that are currently sub-economic, and they can make them economic. We're certainly working on all of those.
But in the near term, as we've just turned now for just a few short quarters from growth to managing at the plateau, we've seen a 25% reduction in CapEx per barrel. We're seeing reductions in operating costs. We're seeing reductions in downtime events.
We're seeing a tremendous amount of innovation and application of new tools and technology to get more value out of this 1 MMbpd business. It's one of the things I've learned coming up through the refining side of the business is sweating the assets, challenging people to innovate and find more value every year in the way we operate can deliver significant improvement. That's the key focus right now.
Going forward, like I say, we've got a long resource life. We've got the advantaged royalty position, which is very attractive, and it creates optionality. I don't want to speculate about what might take us back into a growth mode there, but we're building the capability to do that economically if and when within our overall set of opportunities and cognizant of global demand and other things within our portfolio, we may choose to do that.
Thanks for the question, Doug.
Thank you. We will take our next question from Manav Gupta with UBS.
Good morning. I was wondering if I can pick your brain a little on the ethylene chain margins. We started the year at record lows, saw a massive bounce in Q2.
We are moderating a little, but we are still above mid-cycle, and I think your own project is probably going to start up sometime next year. Just trying to understand global supply dynamics, how much capacity is offline, and also I am trying to understand between refining margins and ethylene chain margins, where do you see normalization happening first? Thank you.
Mark Nelson
EVP, Downstream & Chemicals
Well, thanks, Manav. You picked a couple topics very difficult to predict. I will start with refining maybe, and then go to petchem margins.
On the refining side, I would expect margins to stay elevated in the short term, and the world has 10% of its refining capacity offline today. Exports are reduced due to the conflicts, and quite frankly, the products businesses have less shock absorbers. I would expect margins to eventually moderate as refinery runs recover and export flows increase, but that will take some time.
On the refining side of the business, what we can do is what we can control, and that is help consumers get as much as they possibly can out of our systems. I think we have demonstrated in the third quarter that we are doing that. On the chemicals side, it is debatable today, but somewhere between 5% and 10% of petchem capacity seems to be offline today, and that makes markets tighter, especially from Middle East volumes not flowing.
That likely means that at least through the end of the year, margins will stay a bit elevated, maybe into next year. I would make two observations. First, without rationalization and some project deferrals, markets may very well return to oversupply as flow normalizes, and then maybe second, ethane, especially in the U.S., remains the feedstock of choice.
To your comments, both of those things play to CP Chem's strength. It is an ethane-advantaged portfolio, and they are working as we speak to bring on the two large crackers, one in the Gulf Coast, one in Qatar. Full production both will be next year, but we want those to come online safely and reliably, and they are working hard at that.
Thanks for the question, Manav.
We will take our next question from Lucas Herrmann with BNP Paribas.
Mike, Eimear, thank you very much. Nice to have the opportunity. Question on freight and freight rates and the elevation that we have seen.
It has been a central topic on a number of the calls over here. Just to get some idea, if possible, on the extent to which elevated freight rates are likely to impact upon the refining business, refining profitability, the profitability probably of the organization overall, the extent to which you are long, short, both own shipping and long-term charter shipping at this point, and how it plays to the business. We should be thinking about it, well, we should be thinking about it, but whether it is relevant to you on a quarterly basis in any way.
I think it has been the big mover here this last quarter, Lucas, and it has got a lot of attention. The crude oil prices historically on two basic things, quality and location. Right now, location really matters.
If you are very close to the crude oil that you are going to run in your refinery, you do not have to move it very far. Hopefully, you got it on a pipe and not in a ship. On the other hand, if you are very distant, if you have got to source your crude from a conflict region, the logistics are expensive, the insurance is expensive, time is much longer, and all that works its way from the refinery right back into the netback for your production.
It's an advantage to have a controlled fleet, and we have a significant portion of our fleet that are either ships that we own or ships that we have on long-term time charter, where we charter both the boat and the crew, or a bareboat charter, where we put our crew on that vessel. These are contracts we entered into before the conflict began. They reflect charter rates pre-conflict, which are significantly different than they are today.
We capture that transportation margin in our economics. The other thing that's been interesting is because our upstream portfolio has evolved, we've moved from when I was running downstream, we ran maybe 15% of our crudes were out of our own equity system. Today, we've been up in the 50% range, sometimes higher at certain refineries, and we've got the ability to ensure reliable supply from the wellhead all the way through to the loading rack with transportation that we control and make sure that our refineries are as advantaged as they can be, make sure that our uplift and capture on our crude production is as great as it can be.
We're seeing significant value in optimization globally of our asset base. It is a material contributor to the results you're seeing this quarter, absolutely. I think going forward, until these conflicts are resolved, this is likely to be a part of the story in the future.
Thanks for the question, Lucas.
We'll take our next question from Betty Jiang with Barclays.
Hi. Good morning. Thank you for taking my question.
If I take a step back and actually ask about M&A, just wondering, given the ongoing disruptions around the world, does that change your views around where within the energy value chain perhaps for you to have more or less exposure. How do you think about the inorganic opportunities in general?
Yeah. I'll start, Betty, by saying our portfolio today is the best that it's ever been, both in the near term, in terms of providing energy the world needs and doing it in a way that creates value for shareholders, and then in the longer term, in the growth opportunities in both our traditional business and this emerging power sector that we've been talking about today. There's no gaps or weaknesses that we see that need to be addressed.
That said, you're always looking to get better, and you've seen over the last several years, we have engaged in transactions that have made our portfolio better, that have added assets that have scale, have durability, have strong financial contribution. We have, at the other end of the portfolio, we've moved some things out that no longer compete for capital within our portfolio and for owners. We'll always look to be doing that.
I think M&A is a core competency of our company. I think we've got a track record of staying very disciplined through market cycles of being value-focused, not deal-focused, and executing with really good integration. I don't want to speculate about what parts of the value chain, what parts of the world the conflict may present opportunities in.
We're always evaluating these things, but we generally don't talk about them until we've got a deal that we've actually secured, and at which time we'll lay it all out to you. Maybe last thing is, you talk about the conflict. The history books aren't full of great deals that were done at $100 oil or $10 gas, or high commodity prices.
I think those lessons are important to always bear in mind. Thanks, Betty.
We will take our next question from Phillip Jungwirth with BMO.
Thanks for taking the question. It's been a year since you hired a new head of global exploration, and we hit on AI earlier, and you have a lot of good technology details in the deck, but just more broadly, would love to hear your observations on the progress you've made in the exploration portfolio over the last 12 months, what you're most excited about going forward, and just while it's not maybe deep water, do you see much exploration potential in Kazakhstan, where the government is making a larger push?
Mark Nelson
EVP, Downstream & Chemicals
Well, thanks, Phillip. A lot to be excited about, but let's see where to start. I think I'll start with a high-graded inventory, better technology, and faster decisions, which I expect to lead to improving outcomes.
Our opportunity set is the largest and highest quality I have seen in years. We talked about doubling our acreage since 2024 in the 12 new basins. In the third quarter alone, we added six blocks in the Gulf of America, and blocks in Angola, Nigeria, Guinea-Bissau, and Egypt.
When I combine an expanded portfolio with the new technology, we are getting better imaging and higher confidence prospects. I would expect here over the next few years to have high-impact exploration in the areas like Namibia, Equatorial Guinea, Egypt, and Suriname, just to name a few. Quite frankly, this is the highest confidence outlook I have seen in years.
We mentioned in our comments about the discoveries that we've had, the 15 discoveries. I would expect at least half of those to be turned into tieback positions. The one I just want to emphasize, in case you haven't seen it, would be our Angola 105-4X well.
This is in the prolific Lower Congo Basin. The materials that have been made public indicate an oil and gas condensate column over 2,000 ft and a net pay of 300 ft, with excellent reservoir quality. I suspect it will be better than that.
As we look closer and closer at the data, it has outperformed our pre-drill expectation, and we're working the kind of project definition right now for a tieback to our Sanha facility in Angola. So, a lot more to come, but we are definitely building momentum in our exploration business.
What I might add onto that is that Mark, Eimear, and I were in a review, I guess earlier this week, on our exploration portfolio and some particular opportunities. Your question about talent, we have brought in new talent. I think that brings in different perspectives, different experiences, which we're seeing value from.
Mark mentioned it earlier in his comments, but we've got a very different model for making decisions now and prioritizing this work. I think all of that stuff comes together to yield the optimism that you heard from Mark.
Thank you. We'll take our next question from Bob Brackett with Bernstein Research. Bob Brackett Managing Director and Senior Research Analyst of North American Oil and Gas Exploration and Production Good morning, and let's continue on the theme of improved exploration outcomes.
How does the improved speed, the improved outcome, how does that inform your strategy? Does it allow you to take more risk? Does it drive you to increase your exploration budget?
Or does it actually reduce your exploration budget because your chance of successes are improving? How do you frame that?
Mark Nelson
EVP, Downstream & Chemicals
Yeah, at this stage of the game, and I made some of these comments in my prepared remarks, given the growth in the opportunity set and kind of the new team and new approach we've brought forward, and given from where we come, I would expect us to increase our capital spend next year 50% from our previous baseline last year because the opportunity set is so strong. Over time, you would expect to see us maybe drilling around 20 wells a year, and think about that as half infrastructure, half frontier. We'll continue to do that over time until we see a reason to adjust.
But it's nice to have an opportunity queue that gives us those choices. Thanks for the question, Bob. Bob Brackett Managing Director and Senior Research Analyst of North American Oil and Gas Exploration and Production Very good.
Thank you.
We will take our next final question from Jason Gabelman with TD Cowen. Jason Gabelman Director of Sustainability and Energy Transition, Next Generation Fuels and Energy and Integrated Oil, Refining and Marketing, Liquefied Natural Gas (LNG) Research Analyst Yeah. Thanks for taking my questions.
I just wanted to go back to the Permian, if I could, and a couple there. One, production was off a little bit, still above your 1 MMbpd target. I wonder if that's just normal quarter-to-quarter volatility or something else was going on there.
We saw a comment from your peer that there was non-op disruption. Then the other part on the Permian, if I could, do you see kind of maintaining this stable production helping to mitigate some of the rising gas-to-oil ratios we're seeing in the basin from peers? Thanks.
Mark Nelson
EVP, Downstream & Chemicals
Yeah. Thanks for the question. I would think about this logic maybe.
We continue to focus on maximizing free cash flow there. We do have the inventory depth to grow above 1 MMbpd, as Mike mentioned earlier. But now six quarters at this 1 MMb of oil equivalent, we are driving significant efficiencies.
You can expect to see this number go up 3%, down 3%, but we're going to sustain this above 1 MMb of oil equivalent concept going forward because it is leading to the numbers that Mike mentioned. I'm just going to reinforce one thing, that greater than 25% improvement in CapEx per barrel of oil, that's pretty significant. Our drilling and completion spend is down 40%.
Our facility spend is down 50%. That's all because we're staying in that band. Our gas-to-oil ratio is relatively stable through the end of this decade, and so we can maybe take advantage of some other parties' challenges in this regard.
But I think you should expect us to continue to use the factory model, and our NOJV activities have remained fairly stable through the course of this year. There might have been a little bit of an uptick on workover rigs from our NOJVs, but it's not material to our capital or production. Thanks for the question.
Okay. I think that was our last question. Great.
Sorry about that. We'd like to thank everyone today for your time on being on the call. We appreciate your interest in Chevron and your participation.
Again, please be safe and stay healthy. Katie, back to you.
Thank you. This concludes Chevron's third quarter 2026 earnings conference call. You may now disconnect.
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