Chevron (CVX) Q3 2026 Earnings Call: Cash Flow, Record Production and Venezuela Growth

Key Takeaways

• Chevron reported Q3 2026 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 reached $16.6 billion, while adjusted free cash flow was $14.2 billion. Chevron reduced debt by more than $3 billion and increased cash by more than $4 billion.
• Production was nearly 4 million barrels of oil equivalent per day, including record natural gas production of more than 9 billion cubic feet per day. U.S. upstream output exceeded 2 million BOE/d for a fifth consecutive quarter.
• Chevron plans to double gross production from its three Venezuela joint ventures to approximately 600,000 barrels per day by 2031. Management expects total costs below $20 per barrel, with the program self-funding and no major infrastructure upgrades required.
• The Permian delivered a sixth consecutive quarter above 1 million BOE/d. Chevron intends to sustain production around this level while emphasizing free cash flow and efficiency.
• Management said AI initiatives had captured more than $100 million of value year to date. Chevron is increasing exploration spending by 50% relative to 2025 as its prospect inventory expands.

Key Financial Data

Adjusted upstream earnings declined sequentially due to lower realizations, lower liftings and unfavorable timing effects, partly offset by lower depreciation, depletion and amortization and tax effects. Adjusted downstream earnings increased on stronger refining margins and volumes, which more than offset unfavorable timing effects.

Business and Operating Performance

Upstream and major producing regions

U.S. upstream production remained above 2 million BOE/d for the fifth consecutive quarter. The Permian recorded its sixth consecutive quarter above 1 million BOE/d, while Chevron reported quarterly deepwater production records in the U.S. Gulf of America and record production in the Eastern Mediterranean.

Chevron said its Permian strategy remains focused on sustaining a production plateau and maximizing free cash flow. Capital expenditure per barrel has improved by more than 25%, drilling and completion spending is down 40%, and facility spending is down 50% as the company maintains output within a stable operating range.

Debottlenecking projects recently added more than 85,000 barrels per day of upstream capacity. Chevron announced a 20% capacity increase at TCO’s third-generation plant, a 7% increase at Ballymore and a 33%, or 25,000-barrel-per-day, increase at Anchor.

Venezuela growth plan

Chevron expects gross production from its three Venezuela joint ventures to reach around 300,000 barrels per day by year-end, up 20% over the preceding 12 months. The company plans to double production to approximately 600,000 barrels per day by 2031, using primary recovery.

Management described the program as self-funding, with total capital and operating costs below $20 per barrel. Chevron markets all crude produced by the ventures, with most volumes going to U.S. refiners. The company also said the existing infrastructure has been maintained and does not require major upgrades for the planned expansion.

Refining and chemicals

Chevron achieved record crude throughput across its refining system. More than 80% of its U.S. refinery turnarounds over the past two years were completed with first-quartile duration.

A proprietary catalyst increased distillate output by more than 10% at Chevron’s largest U.S. refineries. U.S. distillate yield reached 46% in the third quarter. Pasadena refinery capacity increased by approximately 15% at nominal cost, while Chevron expects Pascagoula capacity to rise another 7% by 2030.

Management expects refining margins to remain elevated in the short term before moderating as refinery runs recover and export flows increase. In chemicals, management said margins could remain elevated through year-end and potentially into 2027, but warned that oversupply could return without capacity rationalization or project deferrals.

Bakken restructuring

Chevron expects a 50% reduction in Bakken midstream tariffs, which management said will improve upstream returns, expand economic inventory and increase operational flexibility. The company plans to move from three rigs to two at year-end while sustaining approximately 180,000 BOE/d of production.

Long laterals are expected to increase from 60% of activity in 2026 to more than 85% in 2027. The transaction is expected to increase corporate return on capital employed by 0.5 percentage points and deconsolidate $3.7 billion of debt.

Exploration and AI

Chevron added 22 million acres over two years, doubling its exploration footprint and entering 12 new basins. The company reported 15 infrastructure-led discoveries over the same period, at a success rate management said was 40% above the industry average.

AI pattern recognition identified more than 150 leads in the Gulf of America, with 16 prospects advancing into evaluation. Chevron expects to drill around 20 exploration wells annually over time, split approximately evenly between infrastructure-led and frontier opportunities.

Management highlighted an Angola discovery within tieback range of Chevron-operated facilities. The 1054X well encountered an oil and gas condensate column exceeding 2,000 feet and approximately 300 feet of net pay, according to information discussed on the call.

Management Guidance

• Chevron expects fourth-quarter capital expenditure to increase in line with historical patterns, while full-year spending should finish at the low end of annual guidance.
• The company intends to maintain share repurchases within its stated $2.5 billion to $3 billion range.
• The Bakken transaction remains on track to close at the end of Q4 2026. Chevron expects a one-time, noncash, after-tax accounting loss of $3 billion to $4 billion, which it will treat as a special item.
• Management expects immediate improvement in Bakken upstream earnings and cash flow in 2027, partly offset by cash outflows primarily related to taxes.
• Chevron is increasing exploration spending by 50% relative to 2025, supported by 30 net new prospects.
• Project Kilby is targeting first power in 2028 and full energization in 2031, subject to permitting, final investment approval, EPC completion and financing. The project is designed for 2.67 gigawatts and is backed by a 20-year power purchase agreement with Microsoft.
• Management will provide additional details on Chevron’s 2027 capital program in December after review with the board.

Risks and Areas to Watch

Commodity-price volatility remains a major variable. Management cited a $64-per-barrel intra-quarter spread, with oil prices ranging from $68 to $132 per barrel during the quarter. Sharp late-quarter price increases negatively affected working capital, and Chevron expects timing effects when prices rise and reversals when prices fall.

Venezuela carries above-ground and contractual risks. Management pointed to improved fiscal terms, stability clauses, international arbitration provisions, Chevron’s control over crude marketing and revenue flows, and the self-funding structure as risk-management measures.

Elevated freight, logistics and insurance costs are affecting crude economics. Chevron said its owned and long-term-chartered fleet provides an advantage because many contracts were secured before the current conflicts, although the duration of this benefit depends on how long disruptions persist.

The timing and final terms of the TCO concession extension remain under negotiation. Management said discussions had narrowed to core issues and that it saw no red flags, but did not provide a completion date.

Analyst Q&A Highlights

• Capital allocation: Chevron said its priorities remain unchanged: consistent dividend growth, efficient investment, balance-sheet strength and share repurchases through the cycle. The company has increased its dividend for 39 consecutive years.
• Permian strategy: Management is prioritizing efficiency and free cash flow rather than near-term growth above the current plateau. Quarterly output may vary by roughly 3% in either direction while remaining above 1 million BOE/d.
• TCO extension: Chevron described negotiations with Kazakhstan as constructive. Any agreement must provide a competitive outcome for the country and acceptable returns on existing and future partner capital.
• M&A: Management said the portfolio has no material gaps requiring acquisitions. Chevron will continue assessing transactions but emphasized value discipline, particularly during periods of high commodity prices.
• Australian LNG: Gorgon and Wheatstone are already operating above nameplate capacity. Management sees further debottlenecking potential alongside backfill projects and continued reliability improvements.
• Iraq and longer-term growth: Chevron said it is negotiating more competitive terms in Iraq and working on a development plan that would primarily involve drilling, with infrastructure spending expected to be modest and manageable.

Full Earnings Call Transcript

Complete Earnings Call Transcript

Management Remarks

Operator

Good morning. My name is Katie and I will be your conference facilitator today. Welcome to Chevron's Third Quarter 2026 Earnings Conference Call. [Operator Instructions] 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.

Jeanine Wai

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's website. 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 2.

I'll now turn it over to Mike.

Michael Wirth

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 million barrels of oil equivalent per day 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 the 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 from our 3 joint ventures to roughly 600,000 barrels of oil per day, 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 3 ventures, with the majority going to U.S. refiners, 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, and we're on track to reach around 300,000 barrels of oil per day 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

Thanks, Mike. Our strong operational performance is driven by a relentless focus on safe execution, reliability, cost and technology. At around 4 million barrels of oil-equivalent a day, improvements in our base business create meaningful value. In shale and tight, we achieved first-quartile reliability in the DJ Basin during the third quarter by applying AI to anticipate and minimize downtime and skating learnings from the Permian, reducing loss production events by 50%.

In Advanced Chemicals, continued 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. And reliability in Australia continues to be strong, where predictive maintenance, centralized data-driven decision-making and AI help to maximize LNG supply into a tight market.

In Downstream, efficient turnarounds and 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 2 years were completed with first quartile duration. We have pure 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 barrels of oil per day. We announced a 20% capacity increase in TCO's third generation plant, taking total processing capacity to slightly over 1 million barrels of oil per day. At Ballymore, a 7% increase in capacity contributed to record deepwater production in the Gulf of America. And at Anchor, facility capacity has increased 33% or 25,000 barrels of oil per day, 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 2 years, doubling our footprint. This includes 12 new basins with a focus on both sides of the South Atlantic margin and Eastern Mediterranean.

AI is changing what we see subsurface and how quickly we see it. One of our proprietary AI solutions, ApEx, draws on 4 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, build basin assessment in hours, not weeks. And 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 2 years at a success rate of 40% above the industry average. Real-time optimization using AI continuously monitors drilling conditions, recommends actions to reduce nonproductive 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.

Eimear Bonner

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 0.4x. 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 million barrels of oil equivalent per day 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 cubic feet per day led by strong performance in Australia and 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 million barrels of oil equivalent per day, 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 expand our concession next Kazakhstan and as we pursue growth opportunities in Iraq.

Underpinning all of this is an unwavering commitment to consistent financial priorities and capital cost discipline. We're delivering strong performance today while stocking competitive growth options to reliably deliver the energy the world demands for decades to come.

I'll now hand it back to Jeanine.

Jeanine Wai

Okay. Thank you, Eimear. That concludes our prepared remarks. Additional guidance can be found in the appendix of 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 1 question, and we'll do our best to get all of your questions answered.

Katie, please open the line.

Operator

[Operator Instructions] Our first question comes from Arun Jayaram with JPMorgan.

Question-and-Answer Session

Arun Jayaram

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. And maybe you could also elaborate on how you're managing some of the aboveground risk as we think about restarting activity in Venezuela?

Michael Wirth

Yes. So 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. And 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. It 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. And 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. So to me, the best way to manage those risks is to have support of the people in the country and the -- and that leads to an environment where you can resolve any differences that may emerge.

The last thing that I'll say, maybe 2 last things. that are different today than they have been historically is, number one, we are lifting all of the oil. And so it's not going -- 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. And as we go forward, this will all be self-funding. And so the capital will be generated through the revenues in the venture, and we won't be exposing additional capital investments.

So it will 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 that I'll let Eimear talk a little bit about the $20 number we put out there today.

Eimear Bonner

Yes. Thanks, Mike. The cost structure is really competitive. So total cost less than $20 a barrel. So think of that as CapEx on OpEx. And as Mike said, this is a factory like operations. So we'll continue to learn, continue to become more efficient over time. So this is low cost. It's 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 sites and 600 sites and through the end of the decade. So we have the infrastructure we need. And as we build out and as we grow, there'll be more small capital versus anything nature. Those are the key things.

Operator

We'll take our next question from Devin McDermott with Morgan Stanley.

Devin McDermott

So I wanted to check in -- 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 onetime payments or working interest adjustments. And 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 has been going? Any thoughts on time lines? And then I guess the key question is based on your learnings in the process so far what is an ideal win-win outcome look like in your view?

Michael Wirth

Yes. Thanks, Devin. You're right. I'm not going to comment on media reports or specifics, but I can't talk about the process. We continue to make good progress, and I continue to be very encouraged. The discussions began a little bit over a 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, although 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.

There are 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. So 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 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. And they want to see their large resource assets stewarded responsibly, which is something we're very proud to have done for our years there. And 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's a competitive value proposition. And that means that for the capital we've already invested and the capital we would invest going forward that we can get a competitive return. Everybody -- every one of the partners has alternatives in their portfolios, and this needs to be competitive as we've discussed with Venezuela and other assets. And I think each side understands what the other side is looking to accomplish and we're working together to land this in a place that all the parties feel that this is an agreement that meets their needs. So more to follow as we reach significant milestones.

Operator

We will take our next question from Neil Mehta with Goldman Sachs.

Neil Mehta

I just wanted 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've had some time with the Bakken, do you view that asset as core or not?

Mark Nelson

Thanks, Neil. This is Mark. I'll give the front end of this, and then we'll have Eimear comment on the -- kind of some of the economics. But our operational activities that we've been working on in regard to improvements day-to-day and this action with some midstream are all about enhancing value and increasing flexibility. As Mike mentioned in his comments, the 50% reduction in tariff, quite frankly, makes the Bakken stronger. It improves upstream returns. It expands economic inventory, and it maybe most importantly, increases operational flexibility. And this is what excites me the most because it will allow us to evaluate the full potential of the basin.

We've 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 3 rigs to 2 rigs at year-end while sustaining 180,000 barrels a day of oil equivalent production, again, building on the operational improvements that we've made. And 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. So I'm encouraged by what I'm seeing today and the future potential. And Eimear, maybe you can help on the economics.

Eimear Bonner

Yes. Thanks, Mark. Neil, we expect to realize several financial benefits with this in addition to simplifying the reporting structure, as you mentioned. So overall, it increases our corporate ROCE by 0.5% deconsolidates $3.7 billion of debt and delivers incremental recurring earnings. So it will close at the end of the fourth quarter. We're still on track. And when it closes, we'll report a onetime noncash after-tax loss of $3 billion to $4 billion. We will treat that as a special item. And it just reflects the accounting treatment on deconsolidation, not any deal economics.

As we look to 2027, we'll see an immediate improvement in back and upstream earnings and cash flow. It will be partly offset by some cash outflows primarily related to taxes. But we're really excited about this priority operational teams are working together in our centralized shale and tight organization, of which Bakken's and I are part of that, and this transaction does takes a step further and helps us unlock more financial upside. Thanks for the question.

Operator

We'll take our next question from Neal Dingmann with William Blair.

Neal Dingmann

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 manages, I just think the opportunities both organically and externally are just broad. So given the -- I guess my question is, given how much how low the balance sheet is now is your thoughts about next year, have you changed in the way of allocation?

Eimear Bonner

William (sic) [ Neal ], I'll take this one. Yes, 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, I mean, in the third quarter alone, a $64 inter-quarter spread. I mean 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 -- I mean our capital allocation framework and our financial priorities are long standards and they've been in place for decades and over high prices and low price environments, they've really stood as well. So no change to capital allocation. Maybe just to 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. There's no change there. In fact, we're seeing in places like the Permian that we can deliver on the Gold Star 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 to repurchase shares through the cycle, and we have maintained our rate of $2.5 billion to $3 billion of buybacks. And we intend to be buying back shares within that range. And overall, our track record of using this framework, whether it be dividend growth consistency or buybacks for 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 we guided in the Investor Day, and we don't see any major challenges there.

Michael Wirth

Neil, welcome back, and we will give you some additional color on the 2027 capital program in December after we meet with our board. .

Operator

We'll take our next question from John Royall with Piper Sandler.

John Royall

I wanted to see if I could dig in a little on the comments Mark made about increasing distillate yields at the refineries. If you could just provide a little detail around what you've been doing with your catalyst to boost your output on the diesel side. And then maybe just if you could talk more broadly about any other initiatives you're 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

Yes. Thanks, John. Maybe stepping back, I couldn't be more proud of our manufacturing team with another record crude throughput, strong reliability something we've been working on for a while, our top quartile duration of turnarounds. And then these capital-efficient debottlenecking actions, there's a lot of strong momentum. And what's 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've got peer-leading complexity, and that means we've 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 United States 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 3 or 4 years this quarter as well. And so I think what we need going forward to meet customer needs is more of the same. In some cases, that's 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. need today. And then when I think we mentioned this in our prepared remarks, for Pascagoula over the next 2 turnaround cycles will increase capacity there by another 7%. So more of the same to come and couldn't be more proud of the team. Thanks for the question, John.

Operator

We will take our next question from James West with Melius Research.

James West

So I wanted to touch on AI a little bit further. I don't know Mark has had a couple of comments on it. But Chevron was really early in the adoption and implementation of AI, not just amongst the super majors, but the oil industry broadly, oil and gas industry broadly. So I'd love to hear how you're using this at both the enterprise level and then maybe some further context on -- in your exploration programs.

Eimear Bonner

Okay. I'll get us started across the enterprise. We are sitting on both sides of the AI equation. So 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 3 main things. So the business using AI to make better decisions, operate more efficiently to helping meet that growing energy needs. And then 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 as we scale.

Maybe shale and 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 identic assistant to help us optimize production on an ongoing basis. So we've got this deployed and in Permian and back end and in our PC assets. So this is something that we have built in high 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. So there, we've got some proprietary tools that are in development, and we're testing them at a really early stage. And then on the operations and commercial side, human agent teams helping us with turnaround and refinery planning. So Mark, maybe on the exploration side, you can cover up.

Mark Nelson

Yes. 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. And the way I think about it is our goal is to have rapid access to data, reduce cycle time and then increased success rates. And 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. So we're incorporating this throughout the exploration process, including real-time drilling optimization. So it's touching every part of the exploration value chain, and I expect the impact just to continue to grow.

Operator

We will take our next question from Biraj Borkhataria with RBC.

Biraj Borkhataria

I wanted to go to Slide 6, which was very interesting. We obviously spent a lot of time looking at major projects, but these barrels are some of the highest value-add barrels that you have. So I just -- 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 are ongoing? Where are we now relative to nameplate? And what's the potential there?

Mark Nelson

Yes. 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. And we've mentioned some of the examples in the upstream from the 20% increase at FGP to the 7% increase at Balleymore and the 33% increase at Anchor, we are already above nameplate at Oregon and Wheatstone today, and I see more potential for that.

But what excites me even more than just that potential debottlenecking that can exist there. It's the reliability, the world-class reliability we have in Gorgon and Wheatstone is -- allows the customers to get what they need. And having backfill projects, highly competitive backfill projects for decades into the future allows us to continue to leverage that. So I think 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. And I think part of that led to our record production in the third quarter for the combined assets. So more to come. Thanks, Biraj.

Michael Wirth

Yes. And Biraj, maybe offline, Jeanine will follow-up with you. We've done a lot of debottlenecking already at both Gorgon and Wheatstone. And I think we've talked about that on prior calls. But we can share that information with you. So you can see what's already been done there, which is a really good story Mark's just building on.

Operator

We'll take our next question from Jean Ann Salisbury with Bank of America.

Jean Ann Salisbury

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. And I guess, as a related question, how large could Project Kilby get? And what are the gating factors to grow them in your mind?

Eimear Bonner

Jean Ann, we're really excited about Kilby. It's a great project, 2.67 gigawatts 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. So from the really -- 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. And so this is behind the meter power project. It won't put any pressure on the grid in the short term won't raise prices. It's usually non-portable water. And so that's why Governor Abbott on the 6th of August denies that it complies with the standards. So right now, we do have a room to expand.

We could expand this from single cycle to combined cycle. It will all depend on additional permits beyond the permit obviously, that we're working through the system for Kilby as part of our FID decision. So it's going to come down to subject to permitting. Overall, I would just say we're working towards our FID. We have our EPC contract that we're finalizing. We're working through the permit process. We have to secure our financing, but we're on track with Kilby to have first power in 2028 and full energization in 2031.

Operator

We will take our next question from Sam Margolin with Wells Fargo.

Sam Margolin

Maybe just circling back to 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. And globally, it does seem like there's a lot of kind of mega resources or resource whales that are more willing to accept for an investment in partnership than in the past. And so 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's a transferable opportunity with the process.

Michael Wirth

Yes. It's 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've got a very talented workforce. We've got the service providers that are prepared to ramp up with us, et cetera. And it does have, as I mentioned, parallels with other factory development campaigns that we prosecute around the world. I'll go to Iraq as the -- maybe an analog as you talk about large resource holders and willingness and interest in bringing in new investments.

I mentioned already that the terms interact are more attractive than what we've historically seen there. And there -- right now, at least as we're 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. And I think it will have things in common with Venezuela in terms of it will be primarily drilled. There may be some infrastructure work, but I think that, that will be modest and manageable as opposed to a major capital project. And the resource depth there is significant and there's good exploration prospects that are -- would come along with this deal. I've 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.

And so we have been, I think, Eimear mentioned today's 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 breakeven 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.

Operator

We will take our next question from Doug Leggate with Wolf Research.

Douglas George Blyth Leggate

I wonder if I could -- I mean, there's obviously been a lot of chartered by the government, the U.S. government about incentives for drilling and so on. I'm 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 is 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?

Michael Wirth

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 were pretty modest production levels. And as we reached and surpassed 1 million barrels a day, 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 actually continue to have -- 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.

And 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. And 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 subeconomic and they can make them economic. And so 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 million barrel a day business. And 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. And that's the key focus right now. Going forward, like I said, we've got a long resource life. We've got the advantaged royalty position, which is very attractive, and it creates optionality. So 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.

Operator

We will take our next question from Manav Gupta with UBS.

Manav Gupta

I was wondering if I can pick up in a little bit on the ethylene chain margins. We started the year at record lows, saw a massive bounce in 2Q. We are moderating a little, but we're still above mid-cycle. And I think your own project is probably going to start up sometime next year. So just trying to understand global supply dynamics, how much capacity is offline? And also I'm trying to understand, between refining margins and ethylene chain margins, where do you see normalization happening first?

Mark Nelson

Well, thanks, Manav. You picked a couple of topics very difficult to predict. I'll start with refining maybe and then go to pet chem 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 off-line today. Exports are reduced due to the conflicts. And quite frankly, the products businesses have less shock absorbers. So I would expect margins to eventually moderate as refinery runs recover and export flows increase, but that will take sometime. And so on the refining side of the business, what we can do is what we can control, and that's help consumers get as much as they possibly can out of our systems. I think we've demonstrated in the third quarter that we're doing that.

On the chemicals side, it's debatable today, but somewhere between 5% and 10% of pet chem capacity seems to be offline today, and that makes markets tighter, especially from Middle East volumes not flowing. And that likely means that at least through the end of the year, margins will stay a bit elevated, maybe into next year. But I'd make 2 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 United States remains the feedstock of choice. And to your comments, both of those things play to CPChem's strength. It's an ethane advantaged portfolio, and they are working as we speak to bring on the 2 large crackers, 1 in the Gulf Coast, 1 in Qatar full production both will be next year, but we want those to come online safely and reliably, and they're working hard at that. Thanks for the question, Manav.

Operator

We'll take our next question from Lucas Herrmann with BNP Paribas.

Lucas Herrmann

Question on freight and freight rates and the elevation that we've seen. It's been a sort of a central topic on a number of the calls over here. But 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 on shipping and long-term charter shipping at this point and how it plays to the business if we should be thinking about it, what we should be thinking about it, but whether it's relevant to you with on a quarterly basis in any way?

Michael Wirth

Yes. I think has been the big mover here this last quarter, Lucas. And it's got a lot of attention. The crude oil prices historically on 2 basic things: quality and location. And right now, location really matters. If you are very close to the crude oil that you're going to run in your refinery, you don't have to move it very far. Hopefully, you got it on a pipe and not in a ship. And -- and on the other hand, if you're very distant, if you 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 bare boat charter where we put our crew on that vessel. These are contracts we entered into before the conflict began, they reflect charter rates before pre conflict, which are significantly different than they are today. And so we capture that transportation margin in our economics.

And so 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, to make sure that our uplift and capture on our crude production is as great as it can be. And so we're seeing significant value in optimization globally of our asset base. And so it is a material contributor to the results you're seeing this quarter. Absolutely. And 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.

Operator

We'll take our next question from Betty Jiang with Barclays.

Wei Jiang

If I take a step back and actually asked 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?

Michael Wirth

Yes. 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. And so 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. And we have -- at the other end of the portfolio, we've moved some things out that no longer compete for capital within our portfolio. for owners. And so 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 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 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. And so I think those lessons are important to always bear in mind.

Operator

We will take our next question from Phillip Jungwirth with BMO.

Phillip Jungwirth

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, I 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 deepwater, do you see much exploration potential in Kazakhstan where the government is making a larger push?

Mark Nelson

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. I mean our -- our opportunity set is the largest and highest quality I have seen in years. We talked about doubling our acreage since 2024 into 12 new basins. In the third quarter alone, we added 6 blocks in the Gulf of America, and blocks in Angola, Nigeria, Guinea-Bissau and Egypt. And when I combine an expanded portfolio with the new technology, we are getting better imaging and higher confidence prospects. And so 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. And 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 turn into tieback positions. The one I just want to emphasize in case you haven't seen it would be our Angola 1054X well. This is in the prolific lower Congo basin. The materials that have been a public indicated an oil and gas condensate column over 2,000 feet and a net pay of 300 feet 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 Sana facility in Angola. So a lot more to come, but we are definitely building momentum in our exploration business.

Michael Wirth

And what I might add on to that is that the -- Mark Eimear and I were in a review, I guess, earlier this week on our exploration portfolio and some particular opportunities. And 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. And Mark mentioned it earlier in his comments, but we've got a very different model for making decisions now and prioritizing this work. And I think all of that stuff comes together to yield the optimism that you heard from Mark. .

Operator

We'll take our next question from Bob Brackett with Bernstein Research.

Bob Brackett

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 is it -- does it actually reduce your exploration budget because your chance of successes are improving? How do you frame that?

Mark Nelson

Yes. 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 the 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, and 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.

Operator

We will take our next final question from Jason Gabelman with TD Cowen.

Jason Gabelman

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 our 1 million-barrel a day 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. And 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 oil ratios we're seeing in the basin from Pierce?

Mark Nelson

Yes. 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 million barrels a day, as Mike mentioned earlier, but now 6 quarters at this 1 million barrels 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 million barrels of oil equivalent concept going forward because it is leading to the numbers that Mike mentioned. I think I'm just going to reinforce one thing that get 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 JVs, but is not material to our capital or production. Thanks for the question.

Jeanine Wai

Okay. I think that was our last question. Great. Sorry about that. We need to thank everyone today for your time being on the call. We appreciate your interest in Chevron and your participation again. Please be safe and stay healthy. Katie, back to you.

Operator

Thank you. This concludes Chevron's Third Quarter 2026 Earnings Conference Call. You may now disconnect.