Chevron Corporation (CVX) Earnings Call Transcript & Summary

Welcome to Chevron's Investor Day, held here in New York and streaming on chevron.com. I'm Roderick Green, General Manager of Investor Relations. Today's meeting will have 3 sections. Starting with higher returns, followed by lower carbon and closing with winning combination. In each section, our executives will lead with brief comments, a few slides and reserving most of the time for Q&A with sell-side analysts. We'll have 10-minute breaks in between. The full presentation is available on Chevron's website. Before we get started, please be reminded that this presentation contains estimates, projections and other forward-looking statements. The statements are subject to certain risks, uncertainties and other factors that may cause our actuals to differ. Please review the safe harbor statement on the screen and available online. Now I'd like to introduce our CEO, Mike Wirth; and our EVP of Oil Products and Gas, Nigel Hearne.

All right. Well, thanks, Roderick. And good morning, and welcome, everyone to Chevron's Investor Day on a snowy Tuesday morning here in New York. It's good to see everybody in person and to welcome those of you that are joining us online. During the past few years, the world has experienced energy markets, both in surplus and in shortage. We've seen prices so low as to challenge the viability of energy companies; and so high as to be a top issue in election polls. We've seen periods with society predominantly focused on climate change and others with attention concentrated on keeping homes warm and factories running. This illustrates our fundamental belief about energy investment, which must balance economic prosperity, energy security and environmental protection. Affordable energy is vital for economies to flourish. Reliable energy is essential for national security, and we all have a stake in a lower carbon future. When decision-makers over-index on any one of these, there is a risk of unintended consequences and unsustainable outcomes. Through the turmoil, Chevron has remained consistent. We believe that energy should be affordable, reliable and ever cleaner. And we're taking action, with plans to grow both traditional and new energy supplies, while safely delivering higher returns and lower carbon. Our approach is clear and consistent: apply capital and cost discipline to a portfolio of advantaged assets to safely deliver lower carbon energy to our customers and superior cash returns to our shareholders. We're focused on businesses in regions where we can leverage our strengths. And we intend to grow both traditional and new energy businesses because the world's demand for energy is growing too. Today, you'll hear how Chevron, with strong free cash flow, lower carbon operations and new energy solutions intends to sustain higher returns in a lower carbon future and continue to win investors back to energy. Chevron's 2023 CapEx budget is up more than 30% from last year as activity builds and costs rise. This year's affiliate CapEx is down by about $0.5 billion as our project in Kazakhstan winds down spending. Our guidance range is unchanged, as affiliate CapEx is expected to decrease further, leaving room for future CapEx increases up to another $1 billion. In a cyclical commodity business, capital discipline always matters. Our objective is to grow our business in a capital-efficient manner, driving productivity improvements to mitigate inflation and holding on to our hard-earned gains in capital efficiency, returns and free cash flow. You know us by our track record, you can count on us going forward. Now over to Nigel to talk more about our targeted improvements and performance enhancements.

Thanks, Mike. We're growing margins and volumes. Over the next 5 years, we expect unit upstream earnings to increase over 50% at flat prices. At the same time, we have confidence in exceeding our 5-year annual production growth guidance of over 3%, led by the Permian, Tengiz, Gulf of Mexico and other shale and tight assets. Production growth is an outcome of driving returns from our advantage portfolio. Our continued focus on capital discipline and efficiency, combined with growing volumes and improved per barrel margins is expected to deliver stronger financial performance. The Permian continues to deliver high returns, production growth and lower carbon intensity. We constantly optimize our development plans for returns and incorporate learnings from across the Permian Basin. Last year, performance in the Midland Basin exceeded our plans, but fell short in the Delaware, primarily due to higher-than-expected depletion after completing long sitting DUCs. With our large inventory, we're able to shift our operated program to more single bench to high-return developments in New Mexico. Our guidance remains, to achieve 1 million barrels of oil equivalent per day in 2025. We're managing cost pressures and continue to leverage technology to drive performance improvements. Examples include Simul-Frac, where we performed completion activities on 4 wells at the same time; and optimized gas lift, which lowers downtime, minimizes workovers and improve safety. This year, we'll be running 4 grid-powered rigs and 1 natural gas-driven frac spread. Around 40% of our grid supply power will be from wind and solar. At TCO, we've shifted to commissioning and start-up of WPMP and expect to begin operations before year-end. In the past month, we've tied in the fuel gas system and tested the first gas turbine generator. WPMP mitigates fuel decline by converting the fuel gathering stations from high pressure to low pressure through a series of mini turnarounds that will begin later this year. FGP is expected to start up midyear 2024 and ramp up to capacity by year-end. Cost guidance for the project is unchanged. In 2025, the first full year of FGP operations, TCO production is expected to reach over 1 million barrels of oil equivalent per day and generate for Chevron about $5 billion of free cash flow at $60 Brent. In the deepwater, we have a robust portfolio that's delivering strong returns with low carbon intensity. In the Gulf of Mexico, we expect production to grow to 300,000 barrels per day by 2026. The Anchor topsides have been successfully set on the whole. First oil is expected next year, along with the Whale project. Ballymore and other brownfield projects that leverage our existing infrastructure are also on track. In Nigeria, we've extended 3 of our key deepwater leases and we'll begin a 37 well infill program on the Nigerian shelf. On the Angola shelf, we achieved first oil from one of our new capital-efficient, factory-style platform designs. Australia shipped a record number of LNG cargoes in 2022 as Gorgon and Wheatstone together delivered first quartile reliability. The Gorgon Phase 2 project is expected to be ready for start-up in the coming weeks. And the Jansz-Io subsea compression fabrication is underway. Our assets in the Eastern Mediterranean are highly reliable and low in carbon intensity. We continue to develop our resource base there and further strengthen it, for example, with the recent [indiscernible] discovery. With over 175 trillion cubic feet of net natural gas resource, we're building flexibility into how we connect our growing natural gas production with customers. Today, value chain optimization is allowing us to increase our margins through effective utilization of our assets, shipping and access to preferred markets. We're aiming to develop a global network to maximize the value from our advantaged resource. In the second half of this decade, we plan to expand our LNG portfolio. We're developing options to supply LNG to Europe and Asia through the agreement signed last year for LNG from the U.S. Gulf Coast and potentially from our Eastern Mediterranean assets. In our Downstream & Chemical businesses, we remain focused on managing costs and optimizing margin across integrated value chains. We had record 2022 downstream earnings, which included about $2 billion of realized self-help. We expect to carry this momentum forward. And after our growth projects come online, we anticipate earnings to average over $5 billion at mid-cycle margins. We believe in the long-term fundamentals of chemicals and are investing in world-scale projects with advantaged feedstock, a competitive cost and capital structure and the ability to deliver strong project execution. Our U.S. Gulf Coast and Qatar projects both fit these criteria. Our refining system continues to evolve. We're expanding capacity at the Pasadena refinery to handle more oil from the Permian and we're doing capital-efficient unit conversions to reprocess renewable feedstocks at El Segundo and Pascagoula. With the renewable diesel project in Geismar expected online next year, our renewable fuel capacity will increase by 30%. In summary, we're focused on cost and capital discipline, increasing our margins and growing our business. Let's move into Q&A. Please state your name and your company and limit yourself to one question and one follow-up.

All right. So Sam was quick on the move over here. So we'll start over on this side with Sam.

Sam Margolin at Wolfe research. I'm sure we'll spend plenty of time going over your organic opportunity set, and I don't mean to diminish that, but I do want to ask about M&A because it comes up most of the time with [indiscernible]. So capital efficiency in the industry has peaked. It may not be spiraling down, but it's off the peak. The equity market is interpreting that as an inventory issue, but Chevron has made macro commentary in the past. There's plenty of resource in the world. So this is a dislocation that seems like it would be an opportune time for M&A and especially since you have no debt. So I guess framed that way, how are we thinking about M&A right now?

Well, Sam, you probably won't be surprised. I'm going to give you a high-level general answer here. Look, we -- I think we've got a track record in M&A that speaks for itself. We've done well time deals over -- more than the time I've been in this role over many decades before to grow the company. And I think our proficiency there has been one of the keys that's made us a survivor and one of the strongest companies in the world today. So we're always looking. We've got a team that scans opportunities, both in the traditional space and the new energy space constantly. We've got an inventory of over 1,000 companies that we are looking at on an ongoing basis and they get run through a set of filters on asset quality, strategic fit, value, willingness to transact, et cetera. And so we know what companies we like. We know at what values we might like those companies although we don't have to be in a hurry. We don't have a resource issue within our portfolio. We don't have a gap that we feel we need to fill. So we'll be patient. We'll look for the right opportunities at the right time. I think our track record says you can expect us over time to execute transactions. But the history books aren't filled with great deals that were done relatively high in the commodity price cycle. And I would argue that we're relatively high in the commodity price cycle right now. And valuations have recovered. Companies are proud of their assets. And I'm not sure that now is the time you're going to see a lot of deals done. It is still an industry that is highly fragmented, and we're one of the biggest companies in this industry, and we've got 2% market share of the global oil market. So there is room for consolidation in different parts of the value chain in different parts of the world. But we'll look for the opportunities that we think makes sense and create value. I can see you've got a follow-up question on your mind. You're kind of leaning in on me.

Sure. If I'm prompted, I can come up with one. I guess I'll just ask about your gas position in North America because it's quite large. Again, I'm sure people will go over the Permian later, but you had the dot plot on the Haynesville. Prices have been inviting and then disinviting activity there throughout the past 12 months. And then there's an LNG option value, too. How do you think about your natural gas position in the U.S., the structural gas story in the world and then how to commercialize it?

Nigel will take that one. He's done a lot of work on our gas strategy over the years when he was in Australia and in other roles. So why don't you speak to that?

Thanks, Mike. Well, we do have a great natural gas position in North America, primarily from the Permian, but also, as you saw, we added a rig line in the Haynesville. I would say that it's not driven by short-term pricing. It's driven by long-term fundamentals on the outlook in the market. It ties to the LNG position that we've taken for offtake on the Gulf Coast. And we've got a nice growing natural gas position around the world that allows us to combine into a portfolio that kind of have flexibility to access Asia or Europe. So I see that, and we kind of pointed towards it, how do we take advantage of our gas position we have today, the LNG positions we've already signed out to complement what's already in Australia. In West Africa, we have 20 TCF of resource in West Africa. We have 2 offtake positions there. And then potentially towards the end of the decade, there's the option to add expansion it needs to made as we think about what are the right options to take advantage of our resource position there.

Okay. Let's go over here on the aisle.

Nitin Kumar with Mizuho Securities. I want to maybe unpack the Permian DUC issue that you noted in the Delaware Basin. Your solution seems to be moved to a single bench development to go back on track to your development plans. And what I really want to try to understand is, was this a communication issue between zones as their solutions seem to suggest? and if so, when will we be going back to those zones? And what do you expect to see at that point?

Yes. Let me take a first crack at that and then I'll have Nigel get down into some of the specifics relative to go forward in place. I hope you understand the headline is our production guidance is unchanged. 3% compound annual growth rate over the next 5 years. Permian 1 million barrels a day by 2025, 1.2 million plateau later in the decade. So we haven't changed our production outlook at all. We learn every year in the Permian. It's a great big basin. It's multiple basins. You have the Midland and the Delaware, and then you've got sub-basins within each of those. And there is not one game plan that applies everywhere. It's not a homogeneous geologic setting. There's a lot of heterogeneity. And where single bench may work in one area better than multiple bench, there's other areas where the reverse is the case. And so we highlighted some of the elements of the go-forward plan that we have a lot of confidence in, but we learn every year and we evolve every year. Some years, those learnings are maybe more evident to you, but they're always going on. And this is a case again as we look at the learnings over the past 12 months. So maybe you can talk specifically about some of the basin learning, Nigel.

Yes, Mike, thanks for clarifying the guidance. And our production is a function -- our production targets are really a function of our capital and cost discipline. So there's a slide in the appendix, I think, is worth taking note of. As I think about our production goals in the Permian, and we already think about them in 3 tranches. The first is really through our strong royalty position, where we have a mineral interest. It's a significant portion of our production. We have a minimal interest in a large acreage position, which is a strong competitive advantage. We have our NOJV program, which -- where we partner and learn from our competition, where we have working interest and we collaborate to figure out how to do the best across the entire basin. That provides interesting learnings. Then we have our COOP program. Our COOP program represents about 55% to 60% of our overall production. So maybe if I summarize the 2 regions first and then get into the specifics of your question. In the Midland Basin, our performance exceeded plan. In the Delaware, we fell short. And there are a few reasons, primarily driven by depletion. So firstly, we saw some wells impacted by horizontal interference and long-sitting DUCs. We saw some vertical interference where we piloted multi-bench development, primarily on the Southern area of the Delaware Basin and the Western area of the Delaware Basin. And I want to point to the basis of design, because these -- the vintage of these wells were many of them were drilled in 2018 and 2019. They built a long inventory of DUCs into 2020, and it was only during 2022 that most of that DUC inventory got worked off. So on the bottom right, you see this slide. The black line represents the aggregation of those 3 things across all of the wells. Around 70% of those wells were long-sitting DUCs. So that really exacerbated the interference problems that we talked about, or the communication was the word you used. If you take that inventory of wells out and just look at the wells that didn't have that impact, what you see is the light blue line. The light blue line is our forward plan. That forward plan does not have long-sitting DUCs. It is more focused on single bench development, and it has a -- we reconfigured our wells basin. So that's what we've got built into our forward-looking plan. It's why I feel confident in our production outlook. It does have some impact, relatively moderate in our outlook. You will see that we are drilling deeper benches because we're targeting returns, which is why we re-prioritize. So slightly deeper benches. You'll see more rig moves per section. So both of those add a little bit to cycle time. But again, it's not a significant amount. And that we've really built that into our forward-looking design plan. So I feel confident in our performance. I feel confident we understand what happened in 2022. We've applied the lessons learned. We're constantly learning and improving and constantly looking to optimize our basins. So I feel confident in the outlook that Mike mentioned.

So a somewhat unique set of circumstances that came together there and those learnings applied going forward. Do you have a follow-up?

Yes. And I don't need you to -- but if I can look at Slide 8, your mix of low decline in offshore assets changes dramatically by 2027, which is your forecast. From your seat, how do you maintain the treadmill at that point? You have a lot of shale assets contributing to your overall production slate at that time. They are a high decline. So I just want to understand how do you think the production profile could look like? You have 3% CAGR until '27. What does it look like in '28, '29? I'm not asking for guidance, but just shape.

Sure. So actually, there's a slide in the appendix that we could pull up that talks about longer-term growth. We've got multiple growth assets. I mean I think this is the key thing, and sometimes I talk to people that may not fully appreciate that. On the left-hand slide, as you look -- the left-hand side of this slide, what we've got are what you would -- we would kind of classify as our base production assets and pulls the growth assets out and show them on the right-hand side. You see very shallow decline in that part of the portfolio, largely because these are facility limited, not field limited. And so you can think LNG plants, you can think Kazakhstan were the big surface facilities, and we've had some level of drilling that's required to keep those facilities full, but we've got big resource positions that underline those. On the right-hand side, you can see the Permian is going to grow a lot. The Permian growth doesn't end in 2027. We've got more -- we've got a lot of decades of inventory in the Permian. You can see TCO coming on by then. Gulf of Mexico. Nigel mentioned Mad Dog 2 starts out this year, Anchor and Whale next year, Ballymore in '25. We see more in the Gulf of Mexico. And then other shale and tight is a significant part of the portfolio. So there's a balance in the growth side of this. The other thing that I would encourage you to think about is with this large low decline base, as you start to build up a very large position in the Permian, I'll just use that as an example, any given well has the rapid decline curve. But that's got a long asymptotic tail. And you start to stack up dozens, scores and hundreds and eventually thousands of those long tails. And that becomes a relatively shallow decline large tranche of production. And it doesn't take a lot of drilling on top of that to flatten out that set of long tails of production. And so that's why we talk about a plateau in the Permian for quite some time because we can actually moderate the amount of investment that's driving growth and hold the plateau flat with even less capital, and a lot of that to spin off even more free cash flow. So we are not falling off the edge of a cliff anytime soon. Let me just finish it with that. Can we get to some other...

Maybe I'll add a comment, Mike?

Yes, quick one and we're going to get to the...

I think if you go beyond 2027, and you look at some of the acreage position in the Eastern Med, we've got 6 blocks in Egypt. We've got an exploration program. We've got an appraisal well in Cyprus. We'll come to some form of concept select towards the end of this year, I think, around Eastern Med expansion. We've got some of the strongest lease positions in the Gulf of Mexico with great infrastructure. So how do you tie back to existing infrastructure. And then there's another slide around shows our shale and tight is beyond just the Permian in the outer years. Some of that's a little bit less mature. It's in appraisal phase, we're just coming out of appraisal phases. But you see a lot of that ramping up. So I think we've got a strong, diverse complementary asset base for the next 5 years. If you actually look beyond, we've got a nice queue of opportunities too in our strong resource base.

Okay. Let's have Doug and then go to Raj, and I'm going to go to back as I see Jeanine has hand up.

Doug Leggate with Bank of America. Two, can I take two? Is that okay? Two questions. So my first one is on the cadence of the free cash flow growth. I mentioned this to Nigel earlier. So you mentioned the $5 billion of free cash from Tengiz in 2025. What is it currently? And how does the cadence play out over that 5-year period through 2027? That's my first one.

I think if you look at -- you want me to add, Mike?

Sure.

The free cash flow growth is growing approximately $4 billion in TCO, $3 billion in the Permian. There's -- and I use the Gulf of Mexico, as an example, we've not given free cash flow guidance. That's 100,000 barrels a day. of high net cash margin barrels. And then you've got petchem growth in the -- towards the '26, '27 timeframe. And I know you may ask about petchem margins today, but that's not how we invest, right? So if you think about the long-term fundamentals to chemicals, so all of those are adding to that free cash flow.

Especially on the TCO and the Permian, that's really helpful. My follow-up is on Slide 8, I think it is the cash -- the BOE margin slide. Given the significance of the Permian, there's obviously a lot of U.S. gas coming with that. And if I check back the last time oil was around $60, first quarter of 2021, you did about a $9 margin, looks like. So I guess my question is, what are you assuming for gas in the U.S. in that margin expansion? Because obviously, the mix is skewing towards gas domestically.

Yes. I am not going to answer gas.

Yes. So Doug, we've not really changed our long-term price assumptions for oil, for gas, for NGLs, for refining margins. I mean we're in a period of time where we've seen strength in a lot of these different commodities. But fundamentally, we believe that we're going to revert to mid-cycle margins over time. You do see a little bit of a mix change in the Permian over time. But the margin expansion is really driven by lower cost per barrel. So OpEx per barrel down 10% over that period of time. DD&A, we're much more capital efficient. You were around when we were spending $40 billion a year or a decade ago. We're spending a fraction of that today. DD&A per barrel is down 20%. So you're seeing per barrel reductions in costs. We're adding higher-margin barrels into the portfolio, and that net cash margin really just expands as a function of both of those. So I would encourage you not to look at the mix effect and worry too much. You've got gas pricing. It's really about cost efficiencies and scale and as we start to see some of these volumes really come on. Yes. Yes. Okay. Biraj and then Jeanine.

It's Biraj Borkhataria, RBC. Also two. The first one was on the base slide you showed, again, the 1.5 million barrels a day. You name checked Nigeria and some of the work you're doing there in terms of extending the base. Could you just talk about the operating in that environment because a number of your peers have sort of intimated that it's not workable, given the security challenges and some of the things being on there. And that forms a reasonable chunk of that base number there.

It's a reasonable chunk. It's not the largest chunk by any means. And we've been in Nigeria for a long time, Biraj. We've had a very successful joint venture business there, and a lot of success out in the deepwater in Nigeria. We're a little less exposed to the swamp than some of the others. And the issues that you talk about tend to be more challenging onshore than they are offshore. And our portfolio over time has kind of increased our offshore position, and we've got an important but not an enormous position in the onshore as well. So look, we operate in a lot of difficult places. It's part of the business, and I think we've operated very well there. We've seen some significant progress in terms of recovering some arrears in Nigeria that we've been looking to recover. And so it's an important part of the portfolio. And the operating challenges there are things that our people manage. They work hard every day to do that.

The second one was on TCO. And you mentioned it's on budget. I think in the past, it's been a while now, but you previously had a contingency number within the budget because there were some cost increases previously. So is there anything -- any color you can give on -- is it -- how much of that continues to have eaten through -- and how confident are you that will be maintained?

Yes. Nigel was there recently, why don't you take that?

Yes. So I visited several times in the last few years. I was there in January most recently. I would -- the way I'd answer that is that a lot of the risk in this project is behind us. If you think about mobilizing people, mobilizing equipment, this no longer looks like a construction site. Construction is complete. We're now in the active phases of system completion and commissioning and start-up. Right now, we're getting focused on the high pressure, the low-pressure conversion of the field. So that's what improves well deliverability. So that's where a lot of the work and focus is today. It's commissioning utility systems that will allow that to happen later this year. And as we improve well deliverability, we'll provide more supply for the next train and gas compression facility at FGP, which will start up towards mid-year and then begin to ramp up. It's complex, the startup is going to be. It's a lot of activity, a lot of work to do. And we still got about 20,000 people there working. So a lot of activities ahead of us. We have turnarounds to manage as part of our base business. We have a turnaround in the third quarter of this year. We have one just before we convert start-up FGP next year, and we have one between the ramp-up phases. So contingency, I think if you look at the project schedule, a lot of the risk is behind us. We remain on budget with the project schedule itself and now we're focused on as a safe and reliable startup of those assets.

Okay. If we get a microphone to Jeanine back here on the aisle.

Mike, Nigel. Two questions, if we may. The first one is on the Permian and the second one is on Eastern Med. And on the Permian, I love all the information with the type curves and kind of giving us an understanding of what was going on in '22. Can you maybe provide a little bit of commentary on the cost side of things? I know you reiterated the production target. I think prior thinking was it'd be about $4 billion a year or so that you would spend in the Permian. And when you put together everything and what you've learned on productivity as well as inflation, anything related to facilities, is $4 billion a year still really the number?

Can I take that?

Sure.

So I'll start with saying we've absorbed -- we are seeing some inflation pressures in the Permian. We see inflation around the low teens. But the point I'll make is we absorbed a lot of that last year. We hit development cost of less than $8 per barrel, despite some inflation had pressures -- inflationary pressures last week -- last year. We're continuing to develop and improve and constantly looking for different ways to do it. I was in -- I've been there twice in the last 4 months. I saw some great examples of innovation and improvement. Our guidance is just -- is going to be over $4 billion through the period. We do continue to see some of that pressure and some of the adjustments I told you about our development plan. We'll see some marginal changes on cost, but still within that guidance range that we gave previously.

Jeanine, maybe just to add a little bit on that. Most of our -- well, all of our program for this year is already contracted drilling completion crews. So there's no risk in terms of execution. We tend to have contracts that are indexed to market indices, and they periodically will adjust. And so we've actually seen costs that are lower in terms of some of the cost pressure than if you were out in the spot market and contracting for services in real time. We're also seeing technology and performance improvements to the points that Nigel made. I would suggest that if you're thinking about modeling this, I said overall capital guidance for the company is unchanged, production guidance is unchanged. Permian think about it in the $4 billion to $5 billion which was actually the guidance a couple of years ago. Last year, I think we said $4 billion, a year before that, we'd said $4 billion to $5 billion. It's still in that $4 billion to $5 billion range.

Okay, great. We love our modeling. On the -- on West Africa, your slide indicates that it's supporting the base business. You also cited that you have over 20 TCF of resource there. So are we supposed to interpret that slide as there's not really much growth opportunity there? We know you've got Angola, you got the Noble assets there with the -- already the EG LNG plant there that is meant to twin. Well, it's not meant to twin, it's available to twin and you've got great resource there. So just wondering kind of what the growth opportunities, if any, are available in the -- in West Africa?

Yes. So it's part of that base decline conversation, the focus is we've got significant infrastructure invested both in Equatorial Guinea and in Angola. The focus is on affordable and timely supply of gas. So that's where you saw some of the -- and I draw your attention to that small-scale fit-for-purpose platform in one of the photographs, it's really about how do you help create a fit-for-purpose factory-style development to keep those gas assets full, whether they be oil or gas. And so both of the focuses is keeping infrastructure full. We've got more resource in offshore Equatorial Guinea. And we've just signed some agreements to actually start to think about gas backfill for ALNG.

Okay. Over here is Jason, and then I'll come to Roger.

Jason Gabelman from Cowen. I'm unfortunately going to ask another Permian question. So you're suggesting higher CapEx production kind of stable. And broadly, Chevron espouses value over volume mantra. So how do you tie those to the fact that production is flat. CapEx is moving higher in the Permian Basin, but at the same time, you're still a value over volume company. Because it seems like at least in the Permian Basin, there is a bit of, well, we want to hit this volume target, but we're going to increase CapEx to do so. And I have a follow-up.

Yes. I wouldn't -- look, the CapEx guidance, as I said, Jason, is what it was 2 years ago, which was $4 billion to $5 billion to get there. So it's within the range of a little bit of inflation coming into the thing. But we're not talking about a big program change. Where -- if you look at the ramp on rigs, you look at the ramp on completions, you look at the ramp on POPs, it's consistent with what we've been doing. You've got a little bit of inflation that's going to chew into returns. It's still the highest return capital dollar that we can put to work. And if it wasn't, then you would see a change to that.

Great. That's really helpful. And that was just based on feedback we've gotten from investors, they were asking about that. The second one is also something that's been asked just about the global gas footprint and building that out. As you think about Chevron, it doesn't have an LNG or gas trading business similar to some of your peers. And your largest U.S. peer is building out a trading business. And as you think about the ability to compete on global LNG and global gas and be able to sanction new projects, does a lack of that trading business within the company impact your ability to sanction certain projects and capture returns that you think would otherwise be available? And if so, is that something you would be willing to look at expanding a trading business moving forward?

Yes. I want to correct the premise of your question. We do have a gas trading business. We do trade LNG. We may not talk about it the way some of our peers do, but we absolutely have a gas trading business. And there are -- it does not, in any way, shape or form constrain our investment opportunities. Okay. Ryan?

Ryan Todd. The -- maybe a question first on the buyback. You increased the buyback guidance a little bit in terms of the range over the 5-year plan. You've been pretty strategic and cautious, I would say, over the years in terms of walking as far as you felt like the market had derisked or you could kind of conservatively have confidence in the sustainability over the period. So what has changed over the last 12 months that provided you increased confidence to increase the buyback range, either from a macro environment or from your own company operations?

Yes. So let me just frame the buyback within our 4 financial priorities, which have been long standing. Number one is to increase the dividend. 36 years in a row we've done that. Over the last 5 years, 2x the dividend growth of our nearest peer, including growing the dividend through COVID when others did not or even cut it. Second priority is to reinvest in the business. We've been talking about that to generate cash flow, 10% compound annual growth rate on free cash flow over the next 5 years. Priority 3 is the balance sheet. We've got the strongest balance sheet amongst our peer group, less than 3% net debt. We ended the year with nearly $18 billion in cash. On the balance sheet, we need about $5 billion to actually run the company. So you can think of that as $13 billion of cash on the balance sheet that doesn't necessarily need to be there. And then with that low net debt, we got $30 billion of debt capacity before we start to tackle the bottom end of our guidance range on where we would see ourselves through the cycle. So we get capacity is the key point here. And you'll see when Pierre comes in here, and I'll defer to make sure we get to a lot of questions here. More on this, but we stress tested in a low price case, we tested on a higher price case. And what you see is that even if we're in a $50 world for '25, '26, '27, we can sustain a $10 billion buyback. And if we're in a higher-price world, which he'll show you is a $70 case for those years, which may or may not feel high today, we can be at the high end of the range or even have capacity to do more than that. So what we've seen is we've just seen the financial health of the company continue to strengthen, and we're in a position now to sustain a higher rate through the cycle. The last point I'll make is we don't look at buybacks as something we're going to be countercyclical. We certainly don't want to be pro-cyclical. We want to buy back steadily through the cycle. We've done that 15 of the last 19 years. We've bought shares back at an average price of $2 than the volume weighted average for the entire 19-year period, including we bought shares back in 2020, we bought shares back in 2021. So we've had a track record here of steady buybacks through the cycle, and we think we have the capacity to sustain them at the level we've indicated and at the range we've indicated.

And then maybe one follow-up question on Eastern Med. It's an area of an asset that I think probably many of us that were Noble analysts used to spend a lot of time on pre-acquisition and have not spent as much time on over the last few years. But can you talk a little bit about the Tamar expansion, what's happening with the Tamar expansion, maybe the timing on that? And then beyond that, what sort of -- how do you look at the long-term optionality? What are some of the potential outcomes that you're looking at? And maybe what are some of the key drivers or gating processes to whether further expanded Leviathan or incorporate Aphrodite or the material growth opportunity there. So any comments around.

Yes. So the headline is it's a beautiful asset, a beautiful resource, even better than we thought when we bought Noble. There is a lot of opportunity there for expansion, and we're working on those. Now including ideas to help bring LNG to Europe, to help Europe with its gas supply challenges. Nigel referenced Tamar, maybe you can say another word about that and also about the buy...

Like Mike, I also like those assets. I like the assets we've got. It's a very high reliable, low-carbon asset today. Tamar's producing at about 1.1 Bcf a day. We've FID-ed the project to expand it to 1.6 Bcf a day that come online in 2025. Leviathan is producing at 1.2 Bcf a day. We've got a great resource position, 6 exploration blocks in Egypt. We've got the appraisal well in Aphrodite. We found a discovery in August 1, well, so strengthening our resource position, building out the infrastructure, the market. There's a good strong regional market there, that's growing gas demand, and we'll continue to evaluate options for floating LNG with potential other avenues to access European markets. It's a fairly benign ocean. So in terms of floating LNG, it works. So we'll evaluate those options towards year-end, finding the right commercial pathway for the current production we have, the resource position that's developing in the projects and in the future development. So I think this really could be a -- it is a really nice asset today and it has opportunity for growth potential. Really good question earlier.

Ryan, I think Tamar, likely to come online, the Tamar expansion early in the second half of this decade. Leviathan, as Nigel said, we got a couple of options we're still looking at. That production is likely towards the latter part of the decade. Paul, and then the other Paul.

Mike, Paul Sankey, Sankey Research. Just listening to you on Eastern Med, I was thinking about global geopolitical risk. Would you think that your biggest risk is the Russia exposure that you have for transports from Kazakhstan? I know there's kind of threats everywhere, but is there -- would that be the #1 thing that you're worried about? And is there the potential for you to develop alternate routes, which I think slightly came up last year as there was outright interruptions in supply as to whether or not you could find another way to get out. But is that the biggest risk that you face politically? And I'm thinking Australia, there's risk. Eastern Med kind of strangely, there doesn't seem to be so much risk. You've got the California government. You've got the U.S. government. I mean you name it, they're coming from you from all sides. What's your perspective on that?

Yes. I tend not to bucket the risks and the biggest risk and the second biggest risk, Paul, because they're everywhere And they evolve over time. And as you say, there's risks right here in this country that we face. Last year, specific to that pipeline. Last year, there were some interruptions. It had a very minimal impact on our actual production over the course of the year, our people were able to manage through that in a variety of ways. And so look, it's a risk like many other risks that you cited. But it's one that's been managed very well. And the Republic of Kazakhstan has been very engaged, because obviously, very important to the country. And so we work closely with government officials. We work closely with partners. There are a number of international partners in that consortium, all of whom have a stake in keeping that pipeline flowing. And it's important to world markets right now at a time when that production is needed. And so we've been on top of it. The impact has been almost de minimis to this point, and we continue working hard every day.

Is there any update on neutral zone?

Yes. We haven't talked about the PZ. We've got production back up on a 100% basis, north of 150,000 barrels a day. We're looking at some different ideas on field development and expansion, different technologies, and we'll be doing some pilots over the next year or 2 to look at some horizontal drilling, some other types of enhanced recovery technologies that may be appropriate, and we'll talk to you more as we start to develop plans for further growth investments there. Paul Cheng.

Mike, Paul Cheng, Scotiabank. Two questions, please. First, I want to go back into LNG. I think historically, serve on and all the super major integrated approach and so you own the asset, your own the transportation facility. Recently, you signed a supply contract in the Gulf Coast, seems like break away from that. So I guess, my question is that by the second half of the year after decade when you start to expand your footprint, your gain in the LNG, is the strategy going to be more focused on the asset light, or that you're still going to use the traditional model that you want to fully integrate? And also whether that you are concerned because it does seem like there's a lot of LNG projects coming on stream after 2025. I think a rough ton is probably 80 million, 90 million ton per year kind of capacity. So is there a concern?

So Paul, we don't have a model that we must adhere to in terms of LNG development. You talked about the integrated full value chain developments that we did in Australia. It was because there was really no alternative to bring that gas to market. We need it to be in every part of the value chain. If you look at the deals we've entered into in the U.S., we've got a lot of gas resource. There are plenty of people looking to build facilities on the Gulf Coast. And we can enter into offtake agreements to shift the pricing for some of our production here from a Henry Hub price to an international LNG price without having to take on the capital investment and the capital risk in the midstream. Those tend to be lower return investments, just like some other midstream investments that we've tended not to go into. There are other people who -- that's their business model. And that's what their investors are looking for. And we can work with them to access the parts of the value chain where we can generate the returns that we expect and that are competitive within our portfolio and enter into commercial arrangements. So we can approach LNG development in a variety of different ways, always looking at driving returns for our shareholders and taking advantage of the opportunities that each market can offer up.

Yes. And how about it seems like a lot of capacity coming on stream, is that a concern?

It's like so many parts of this industry, Paul. You get surges of capacity and markets tend to get oversupplied and then they work that capacity often. So LNG has been like that, petrochemicals refining. You can -- so will there be too much LNG capacity at some point in the future? Probably. Will that be a structural impediment to investment for a short period of time? At some point, it may be. But demand for LNG is growing demand for gas in the world is growing. And I think you'll see, as we saw in the last wave of projects, they tend to slow down when people start to get right up against financing and final investment decisions, if it looks like there's too many of these things coming at once.

The second question is on inflation. I think everyone talked about the onshore. Can you talk about the off-store, what kind of inflation rate that you are seeing since that? I think that's also a part of your future growth in the Gulf of Mexico and all that. How that impact on your development pace?

I'd like to highlight that the inflation rates primarily in the Permian, and Mike made some good comments around how they're index. Inflation rates more globally are in the low single digits, Paul. And specifically, the Gulf of Mexico, all of our rigs for the near-term development well contracted up. So we don't see any real change to that, but mainly in the low single digits internationally.

Low to mid probably.

Alastair Syme of Citi. I just wonder if you could give us a quick map of the other shale and tight piece. Just one question. This is the overview of how those different businesses back up.

Go ahead.

There's a slide in the appendix, actually, which shows if you could pull it up. Thank you. So if you look at our shale and tight assets, it was pointed on the far right side of our growth picture is around 200,000 barrels a day of growth, primarily driven by the 3 assets we have in Argentina. El Trapial is in development. The other 2 are just wrapping up appraisal. DJ Basin is the other primary growth. We've got rig lines being added there and activities. We're going to add almost 70% more POPs in '23 than we did in 2022. Still a flexible base. Haynesville, we're just adding 1 rig line. Part of our -- I talked about that a little bit earlier on part of our natural gas position. And one of the other reasons we're doing this is part of the depletion conversation we talked about earlier on is offset wells, other operators are in the Haynesville. It's a good time for us to be there. And it does attract good returns. And the Kaybob Duvernay, it's just holding flat. We've got a small amount of rig lines running there just to kind of hold our base production. Alastair, does that answer your question?

[indiscernible]

So yes, low cost, low development cost, high liquids yield. The issue is around risk. We've taken some commercial offtake positions with a pipeline deal that we've signed. There is commercial risk. But what I would say is, look, this is a typical shale and tight development. We can pace our development as we see signals around things are encouraging or that we see risk growing, we can either accelerate or slow down our activity. So we're going to take a very measured but deliberate approach to how we develop the Argentina resource.

Okay. I'm going to try to squeeze in a couple more quick ones here. John, and then -- yes. I'm going to try to not allow people to double up just to get a spread around everybody.

John Royall from JPMorgan. So on the $15 billion to $17 billion CapEx guide, can you talk about the moving pieces there around not changing the guidance? There's obviously been a lot of inflation. What are some of the offsets going the other way? And then longer term, what do you think of as an optimal mix of growth versus sustaining once you're no mega projects post Tengiz?

Yes. So I mentioned Kazakhstan coming down. That's one of the things that allows us some more room. We've got other projects that are beginning to ramp up in petrochemicals to petrochemical projects that we've sanctioned. I just talked about some of the sale activity we've got a project at our Pasadena refinery. There's a lot of puts and takes, John. And as we look at managing this for ratability and for execution, and we're committed to executing well, we're making trade-offs within the portfolio that allow us to stay within a disciplined range and a predictable set of outcomes. And so you'll see deepwater Gulf of Mexico projects. We talked about Anchor and Whale starting up next year. That opens up room in the years subsequent to that for other projects to come in. So there are constantly projects that are reaching their peak spend, they are coming off their peak spend. And we trade those off as we stay within the guidance.

Great. And then I don't think you've gotten a question on Venezuela yet, so how are things progressing there? How long do you think it will take to scale that up? And what's a reasonable expectation for Chevron's production in Venezuela?

Yes. So it's very early days. We have begun lifting crude from Venezuela and bringing it to markets in the U.S. We've been running it in our own refinery. We're getting do supply other customers with oil. We've got some people on the ground. We've got some expatriates back in there. We've assumed some key management positions in some of the [indiscernible], and we're seeing production respond. I mentioned at the fourth quarter call that production has gone from 50,000 a day to 90,000 a day, our share in the ventures, [ where it's ] a little bit higher than that probably today, so we're seeing some early progress, still focused on safety and asset integrity. And we'll go slow there. The shift in policy by the U.S. government is relatively recent still. We've got questions about elections coming up and other things and so I would expect us to go slow. And we'll update you as we move along, but I wouldn't think of that as a real growthy part of the portfolio until we've seen some more progress. Behind John and then Lucas on the aisle. And Neil, we'll get to you too.

Phillip Jungwirth with BMO. 2 questions on reserves. It was good to see the production growth reiterated through 2027. Just wondering if you could talk about proved reserve growth or whether you could maintain proved reserves and just thinking about it in terms of a lot of the major projects are booked. And then you're somewhat limited under the 5-year rule in terms of shale and tight and Permian bookings.

Yes. So maybe we can pull up. We've got an appendix slide on reserves and resource. And I don't want to spend too much time on it, but over 10 years, we've been at 99%. And if you were to look at a 1-, 3-, 5-year period, they're [ 97 or 102 ]. They're -- they really have been relatively consistent around that. On the resource side, we've gone from 65 billion barrels of resource 10 years ago to 78 billion today. And not only has it grown 20%. The resource quality is much better. 10 years ago, we had Canadian oil sands that we were unlikely to get to. We had Gulf of Mexico shelf. We had some North Sea. We had gas in the far northern regions of Canada for Kitimat. A lot of the stuff that's going on in the portfolio was unlikely to compete for capital. It's been replaced with much-better-return, "more likely to be developed" resource. So it's sitting there with 78 billion barrels of 6P resource to keep feeding reserves over time. We do have some things with the 5-year rule that we'll govern how fast some of that comes into proved reserves, but we don't have concerns about reserve replacement.

And then my follow-up question would be on that 6P resource slide and as it relates to the Permian and just wondering if the change in the development approach in the Permian that you'll be taking in 2023 and beyond would impact that 6P resource or more importantly the PV10 of that resource.

Yes. The Permian resource has grown considerably over the last decade, as you would imagine. It's come off just a little bit. Some of that growth, we've -- based on the learnings that Nigel referred to, we've actually pulled some of that resource back down. It's 27 billion barrels, so it's about 1/3 of our total 6P resource. Just to put it in perspective: At last year's production rate, that's 100 years of resource that we've still got sitting in the Permian, so when I say we'll be working on this for a while, that's one of the reasons why I say that. The other thing, I'll just reiterate. Nigel mentioned it earlier, but this is royalty advantaged. It's 27 billion barrels, most of which has low or no royalty because it's fee property. So the Permian is -- it is a resource I wouldn't trade for anything in anybody else's portfolio in the industry. Okay, I was going to get to -- yes, to Lucas and then Neil. We're just running a touch overtime, so [ I'm going to ] try to be quick.

All right, Mike, one question. And in ways, it goes back to Paul's question and it's really around monetizing gas and LNG strategy. Firstly, remind me of your position in Venezuelan gas. I ask simply because of the efforts at the present time to keep Trinidad and Tobago [ filled -- well ], not your asset, obviously, but I guess, secondly, as I start thinking about your portfolio; and [ alleged ] disappearing in other facilities, Egypt, Equatorial Guinea, North West Shelf, Indonesia, [ whirlwind tour ]. I mean you have resource located around almost every one of those facilities and, I would guess, an opportunity to monetize, so Nigel, I mean, the question is -- does go back to Paul. It's to what extent that starts to become front and center of mind in terms of monetizing gas in a very, should we say, financially beneficial way.

Yes. So we do have some resource offshore -- some gas resource offshore Venezuela. It's tricky, as things are in Venezuela, but the broader point that you're making, Lucas, is I think one that you're going to see as a really durable feature of our development going forward, which is we've got resource near facilities and we can do highly efficient brownfield development, whether you're talking about secondary, tertiary, quaternary benches in the Permian; whether you're talking about keeping LNG facilities full around the world; Kazakhstan, the projects that we're doing there to maintain plateau. The intent is to look for -- Gulf of Mexico brownfield tiebacks, right, and further tiebacks. The point you're making is something that is front and center in our planning. It's highly capital efficient and it's shorter cycle times and lower risks, so I think you'll hear us talking a lot more about that in the years to come. Okay, we're going to go to Neil. And then I got to take a break -- or your next speakers are going to be in here and Nigel and I will still be sitting up here.

I'll be quick, which is there was an organizational change that was made at Chevron. And Nigel, you're front and center in collapsing the upstream and the downstream organizations. Can you talk about what that has done in terms of your ability to drive your strategy forward?

Do you want to [ talk away ], first? Or...

No. Go ahead.

So actually it hasn't changed our strategy. What I think it does is it brings the best out of what we do in upstream, downstream, midstream together. We have identified value that existed between the segments that wasn't really material or wasn't visible before, but it's really about bringing this consistent and disciplined execution, whether it be to how we think about using existing infrastructure to monetize resources, to Lucas's point earlier; whether we talk about how to drive asset class excellence. Our shale and tight assets are now all organized under one direct report, so you start to think about running those as a business proposal together. How do you leverage best practices? The same in our complex facilities in upstream. And what we're seeing is there's things that are common across upstream, downstream and midstream. Turnaround excellence is an opportunity for us, so what we're trying to do is bring out the best in what we do today and accelerate progress. And with all those organizations being under one, it's a little bit simpler to actually do that, so that's what I'm actually excited about.

Okay, we are going to take a "slightly less than 10 minute" break because I think we're going to restart on schedule. Coming in next will be Jeff Gustavson and Eimear Bonner to talk about new energies. And Eimear will talk about technology, including [ ask her about ] the Permian, for those of you that have got all of these Permian questions. Eimear is doing a lot of interesting work in the Permian Basin. So thanks for joining us today. And we will break and be back at less than 10 minutes. I'll let the [ pushers ] get you guys back in the room when the time comes. Thanks. [Break]

Hi, everyone. I'm Jeff Gustavson. And with me today is Eimear Bonner. I'll provide an update on the progress we're making on our lower carbon objectives and Eimear will share how technology is powering today's business and building tomorrow's. Our strategy is clear: leverage our strengths to safely deliver lower-carbon energy to a growing world. That means focusing on lowering our portfolio carbon intensity today while growing new, lower-carbon businesses and solutions for tomorrow. We're driving our renewable fuels, CCUS, offsets and hydrogen businesses forward, which we believe will also generate attractive returns and cash flows. We're making progress towards our upstream CO2 intensity reduction targets. We continue to prioritize the projects expected to return the largest reduction in carbon emissions cost efficiently. We have plans to advance over 100 projects this year to lower the carbon intensity of our operations, focusing on energy management, flaring reduction and methane management, among others. Our goal on methane is simple: keep it in the pipe. In the U.S., we're already a leader in this space and plan to continue making progress through technology and partnerships. We're continuing to grow profitable renewable fuels value chains. We're working with partners to secure diverse feedstocks and realize value in the oilseed crushing margin. By building off REG's capabilities and assets, Chevron is now the second largest bio-based diesel producer in the U.S. and we're halfway to achieving our 2030 capacity target. We're using our existing distribution channels to place these volumes in markets to capture the highest margin. In renewable natural gas, we're growing our partnerships with existing dairy farmers while looking to expand our feedstock mix. We continue to grow our retail offerings with more stations in more states. In carbon capture, we're taking early actions that aim to establish future large-scale, profitable projects. We're focused on securing pore space, creating regional hubs and advancing capture technologies. We're developing opportunities in the United States and Asia Pacific regions where there are concentrated emissions and good geology. We'll continue to take a disciplined approach, only selecting the best projects to invest in. In the area of carbon capture, we've secured over 1 billion tons of CO2 storage resource both on- and off-shore in the U.S. Gulf Coast, near large industrial emitters linked to natural gas value chains. In the Asia Pacific region, we're working with JV partners under 3 separate permits to study storing CO2 in areas off Australia's northwest coasts to capture existing LNG emissions and grow new hydrogen value chains. Lowering costs through technology is critical to building a profitable CCUS business. We're making strategic investments to lower the costs of capture, using our own assets to pilot new technologies. And we're studying the feasibility of transporting liquefied CO2 to create pathways from high-emission centers to storage locations. In hydrogen, we're taking early action for a high-growth competitive business. Chevron is well positioned to leverage our existing capabilities and assets to deliver reliable, low-cost hydrogen to existing and new customers. We're evaluating over 50 opportunities and are focused on developing production hubs that initially leverage existing natural gas value chains while also enabling technology. We'll continue to take a disciplined approach, only selecting the most attractive opportunities for Chevron. Collaboration with partners will help enable faster end-to-end solutions, acquire early-mover customers and set the foundation for future scaling of a larger hydrogen ecosystem. We're studying several hydrogen and ammonia production facility concepts across the U.S. Gulf Coast region to link our growing natural gas production base with our new CCUS resources. We're working on multiple projects across California, anchored by our Richmond Refinery, to derisk technology and support expected future demand. In the Asia Pacific region, we're continuing our work with JERA, a longtime partner and customer, to explore codeveloping lower-carbon-intensity fuels in Australia. We're also collaborating with partners to study the development of hydrogen and ammonia from renewable energy sources. To summarize. We're making progress both lowering our current carbon intensity while growing new profitable lower-carbon businesses and solutions to scale. Technology is critical to powering our business today,and to realizing our future ambitions. I'll hand it over to Eimear to share some of the key technologies that we're developing.

Thanks, Jeff. We're focused on technology that delivers energy solutions for today and transforms the energy system of the future. Starting with safety. In our Salt Lake City refinery, we've piloted the use of robots to inspect tanks. This keeps our people safe and out of confined spaces, and we're moving to scale the solutions across our refineries. On higher returns, we're using technology to optimize field development. For example, we've developed a new technology to get higher-quality seismic images faster. We've used this in the Gulf of Mexico and in other challenging geological environments. Additionally, in Australia we're testing innovative digital tools that integrate operational, reservoir and economic data. This will enable faster field development decisions, improving cycle time from concept to production. On lower carbon, a key focus area is methane management, as you've heard from Jeff. We're leveraging machine learning to predict and prevent emissions. And we've tested advanced technologies, including satellites, to detect and make timely repairs. As we look to the future, technology solutions and innovation are critical. In our shale and tight assets, we're utilizing subsurface technologies and advanced materials designed to increase reservoir recoveries. To automate facilities, we're deploying monitoring systems on subsea pipelines to reduce unplanned downtime and the need for offshore interventions. For new energies to be competitive, we must advance technology at scale and operate cost efficiently. Let me give you 3 examples to illustrate. One, we're developing and growing technologies to have feedstock flexibility for renewable fuels. Two, we're piloting technologies in the San Joaquin Valley to learn how to capture carbon efficiently. And to better understand CO2 storage and reservoir dynamics, we're leveraging fiber optics, novel seismic and high-performance computing. Three, we're evaluating technologies to produce lower-carbon-intensity hydrogen. We're investing in liquid organic hydrogen carrier systems to solve one of the biggest challenges of hydrogen: how to store it and transport it over long distances. We've been solving difficult energy challenges for decades. And we're working on the next generation of breakthrough technologies to deliver the energy solutions of tomorrow. Let's move to Q&A. Please state your name and your company, and limit yourself to one question and one follow-up.

Okay. I think Sam had his hand up first right over here.

Sam Margolin, Wolfe Research. My question is on carbon capture. I think, under the Paris accord and the UN, something like 15% of GHG emissions can be addressed by carbon capture, but that's essentially like 100% of scope 1 and 2 across the industry. But what we're also seeing is a lot of greenfield projects because carbon capture incentives are very robust. And so people are almost creating emissions just to capture them, so the question is how big do you think your carbon capture business can get. How much of your initial scope 1 and 2 emissions can you address? And then is this one of the markets within low carbon with one of the largest growing TAMs that you see given the policies?

Sorry. Can you repeat the last part of the question?

How does CCUS compare in terms of addressable market growth versus other low-carbon verticals...

Okay, yes. So to start with, I mean, a very prospective sector. I won't get into the specifics on how big this could become, but on any scenario that you look like -- or that you look at in the world of carbon capture is a part of any net zero pathway. So we're talking gigatons, many gigatons of storage for a business that today is, I believe, less than 50 million tons are being stored on an annual basis, so we have a long way to go. This is a very large addressable market. It's a critical technology to support the energy transition for hard-to-abate sectors, some in particular, including our own. So that gives you a sense of the size. We -- last -- or 1.5 years ago, we provided some guidance on how big we think this can become in our own portfolio; released guidance on 2030 volumes being 25 million tons per year, both CCUS and our carbon offsets business, so that's a marker that's out there. We're making good progress towards that target, but we still have obviously a long way to go, not just us but industry-wide. I'd highlight one project in particular, our Bayou Bend development in the U.S. Gulf Coast. There was a great slide on that asset. We've done a lot of work over the past year to grow our pore space, our land position. We think we have some of the best pore space in that area, almost 150,000 acres with over 1 billion tons of CO2 storage. You're in a location with good geology but also concentrated industrialized emissions, some of our own emissions but also refinery, pet chem, cement, steel emissions all in that area. And the customers we're talking to in that space are motivated; have net zero targets of their own, lower carbon intensity targets; and are very interested in talking with us in how they can participate in that regional hub development. And that's just one hub. So that gives you a sense of the size. In terms of our own emissions, all of these new energies businesses, we're looking at third-party opportunities, as I just mentioned, with -- at Bayou Bend in the U.S. Gulf Coast, but we're also looking at how we can deploy these technologies to abate our own emissions. And you might talk about in a little bit, Eimear, some of the work we're doing in the San Joaquin Valley to test technology but also abate some of our San Joaquin Valley emissions. We're looking at large refineries around the world. We're looking at large upstream plants. We already have a large CCUS project associated with our Gorgon asset in Australia. And there will be more opportunities as we go forward. Eimear, you might talk about the technology a little bit in San Joaquin Valley.

So to support all of those ambitions both in our business today, so our traditional business today and in Chevron New Energies, carbon capture is a focus for us. And particularly, we're focused in lowering the capture costs; and understanding then, when we do capture CO2, how to store it safely and efficiently in reservoirs. So really 2 main things, lowering capture costs and storage. Jeff referenced some of the pilots that we've got ongoing. So we're studying a few different capture technologies to understand which one might work best with our facilities. And we've got one running in San Joaquin today and we're doing that pilot. It's absorption-based technology with Svante. This was a company that we invested in back in 2014, and we're now testing it on one of our operating assets. We have another plan in the next few years to test another capture technology. And then we're also going to test concentrator technology, so how to integrate some of those together. So we believe that the pilots that we have ongoing today and those that we've planned in the next few years will really help us understand that first technology objective, and that is how to capture it cost efficiently. And from a storage perspective: This is an area where we're leveraging decades and decades of subsurface expertise and reservoir characterization, reservoir simulation to really model and have the analytical tools that are allowing us to not only look at where is the best place to store CO2 but how to store it and how to ensure good storage efficiency in the reservoir and how to keep it in the reservoir. So those are the 2 technology things that we have that support capturing carbon from the businesses that we operate today but also in pursuit of growing CCUS as a future business.

So that's a great combination of 2 of those things, the internal customer base scaling technologies but the external size of the market. And you asked about which of these businesses were most could scale the -- to be the largest or the fastest. I can't pick a favorite here. We like them all. Renewable fuels, we've seen more progress sooner on the back of the REG acquisition last year, but as I talked about, we're building some very large foundational projects in the CCUS space. Hydrogen will follow. Carbon offsets and other emerging technologies like geothermal will also be a part of the mix. They're all important for the company. Thanks for the question. We'll go right here, Paul Cheng.

Paul Cheng, Scotiabank. 2 questions, please. First, can you talk about how you guys view internally on the financial metrics when you make decision on project? How is that different than your traditional oil and gas or refining projects? I mean clearly you talk different nature of the projects, that they will be different, so trying to give us a framework how should we look at that from a company standpoint. The second question is that on RNG. I think the company does have operation over there and that 1 of your European [ cousin ] -- actually 2 of them, make some pretty sizable acquisition, trying to jump-start and accelerate the pace. Is that something that may be suitable for Chevron? Or you believe that your own, the internal opportunities or organic opportunity is sufficient for the pace.

So thanks for the question, Paul. On metrics, the metrics are the same. We use the same metrics to measure the economics for these investments that we use for any investments we make across the company. And the returns really matter in this space. We need to be able to generate attractive returns to make these businesses sustainable. There are other drivers here. There are lower carbon, CO2 abatement, both our own and other company drivers, but at the end of the day, for these businesses to be sustainable, we have to generate returns. And we want to generate high returns. And given the size of these markets, the growth in these markets, the skill sets that we bring to all of these sectors which are critical for any net zero pathway, we feel that we can do that. Now the risks are greater. The bands of uncertainty are wider. I compare it to our exploration business, to use an analogy. You need to understand those risks when you go into these projects. The investments also tend to be smaller, at least today, versus some of the other investments we're making across our traditional business, but the same metrics apply. And as we go forward, hopefully, we'll be able to work on the technology; lower the costs; sign up customers; have more clarity on the policy, incentives that marry with these businesses. And we'll be able to narrow those bands of uncertainty, but we use the same metrics. I think your second question was around M&A, if...

[indiscernible] specifically for RNG...

For RNG, yes, for RNG. We're clearly -- M&A is a part of our toolkit as an enterprise, and we have a good track record on M&A. We need to be very disciplined in any acquisition that we make. We're looking at organic growth in this space. We're also looking at inorganic growth just like we do in our traditional business. We feel like we have a strong portfolio of early opportunities in this space, so anything we bring in inorganically will have to compete with some of the projects that we laid out in the presentation. We -- in the renewable fuel space, in the new energy space, the best example of where we've used M&A was the REG acquisition last year. Very happy with that acquisition, happy with the assets, even happier with the people. We're on track with our Geismar RD expansion in Louisiana, which should come online in early 2024. The EBITDA forecast that we've put out in 2025, $500 million to $600 million in EBITDA by 2025, is intact. We feel comfortable with that. We're realizing synergies and we're realizing the benefit of the complementary skill sets those 2 companies bring together. So we do have a history in this space. I won't comment on anything specific, to a specific sector, RNG or elsewhere, but this is something that we'll continue to look at going forward. Thanks for the question. I will go here. I think you were next, sir. And then we'll move to this side of the room.

Jason Gabelman from Cowen. A couple of years ago, I think you put out targets around the low energies business of $1 billion of cash flow from $10 billion of investments over, I think it was, 8 years. Can you discuss, have either of those numbers changed at all? And has the makeup within those numbers changed at all?

Yes, thanks for the question. The $10 billion hasn't changed. We're sticking with that guidance. $8 billion -- just to remind everybody: $8 billion was directed to growing these new low-carbon businesses. $2 billion will go to lowering the carbon intensity of our existing business. It would be great, Eimear, if you stepped in here in a second and talked about some of the progress we're making on our marginal abatement cost curve projects. We're not changing that guidance. We'll continue to look at that. We'll look at the opportunities that come into the portfolio. We have more -- we have longer queues now than we can invest in, but not all of those opportunities are investable opportunities, and so we'll continue to monitor that and we'll update guidance as appropriate. No change to the $1 billion of cash flow from operations in 2030. We feel very confident. With that, renewable fuels is already cash -- generating cash today. And I just mentioned we expect it to generate much more cash in the next couple of years, largely on the backs of the Geismar renewable diesel expansion, projects like our Bayou Bend project in the U.S. Gulf Coast. We're working hard at signing up customers to that. It has to work for both sides. We have to be able to generate attractive returns. And then a hydrogen business. We're doing a lot of study in the hydrogen space to drive even greater cash flows, I think, next decade. And so that's where we sit with the capital and where we feel confident about the cash flow from operations target. Thank you very much for the question. You get one follow-up...

So on lowering -- maybe I'll just talk about lowering the carbon intensity of our existing assets. So Jeff mentioned the marginal abatement cost curve. So this is the approach that we use. We look at all of the opportunities as a portfolio, and our goal is to abate the maximum amount of carbon for every dollar that we spend. So we have a large portfolio of projects, over 100 projects. We've got great momentum building around execution last year and we actually grew the portfolio a lot. We executed 13 projects. We'll execute 3 to 4x the number of projects this year, so that part of the $2 billion, we're really putting that to work. An example of something, just to kind of bring it to life, would be a facility project. I've mentioned the one in Nigeria, where on a gas turbine we upgraded the [ air ] filters. And the upgrades were to mitigate [ filing ] in the compressor section. That increased fuel efficiency. That mitigated [ filing ]. That extended duration between maintenance outages. That lowered the carbon intensity of that unit but also maximized returns because there was that reliability benefit as well. So we see example of examples. So that's an example of one of the projects within that marginal abatement cost curve portfolio that's focused on lowering the carbon intensity of our existing business.

Thanks, Eimear.

Great. And my follow-up is on the Inflation Reduction Act. You mentioned your targets are unchanged, but it would seem the Inflation Reduction Act would support some of the economics a bit. So if you'd just discuss how that act has impacted the economics of what you're investing in, in the U.S. and if anything in the hopper becomes more or less advantageous as a result of the IRA.

Yes. And as we've said in the past, policy support is important here. We're focused on areas where we have capabilities, where we have assets, where we have existing customers in policy-enabled markets, so that's a key part to the -- especially the early stages of growing these businesses. So the IRA is a step in that direction. It's consistent with that broad policy support. There's a number of details that need to be worked through on that bill. We, among with many others, are working through those details, but a step in the right direction. I'd just say it's just one element where many elements need to come into place to make these businesses scale. Policy support is one of them but not just broad: tax incentive or other support; local support; permitting; support very, very important for projects like the Bayou Bend project that I noted on the U.S. Gulf Coast. Commercial arrangements. These are new commercial arrangements between customers and suppliers, CCUS, hydrogen, renewable fuels. There's a lot of demand from customers, but at what price? How do you work through those agreements? That is going to take some time. And finally, some of the technological examples that Eimear provided. I mean these businesses are enabled by policy, number one; but technological advancement, number two, to lower the costs to make them more viable for longer with less policy support. So IRA, one step but just one overall step. It hasn't changed our broader plans or strategies. Thank you. We'll go right up front with Doug.

Doug Leggate from Bank of America. 2 quick ones, I hope. LCFS credits have obviously collapsed quite a bit over the last couple of years. What was embedded in your $1 billion assumption? And how does that play into the trajectory to get there? And the related follow-up, if I can just throw it in there as well, is the company broadly has talked about a 10% CAGR in free cash flow through 2027. Approximately what do you see, the contribution from the new energies business over that period?

Thanks for the questions. On LCFS, yes. Given supply-demand dynamics in California, we're at 5-year -- I believe it's 5-year lows for LCFS prices. Certainly that is an incentive that is important for the renewable fuels business, but first of all, there are many incentives that make up the basket that support renewable fuels business and other businesses that we're looking at in California and elsewhere. And our longer term -- we make longer-term projections just like we did on our commodities, on the commodities that we sell, oil and gas. We don't release those externally, but that's something we look at. We do see LCFS prices strengthening in the years to come as carbon regulations continue to tighten, but it's just one component. And policy is just one component. What's really important in running our renewable fuels business is we take a full value chain approach. It starts with feedstocks and being able to run diverse feedstocks in our refineries. Eimear can touch on some of the technological advancements that we're making there. It goes into running very capital-efficient assets, either existing Chevron assets or the new assets we've acquired through the REG acquisition. And I mentioned the Geismar expansion, which is on track and on budget. And then it's accessing the right sales and distribution channels, and this is where REG and Chevron really complement one another. And one plus one equals much more than two. And that's very important with these policies' change. The LCFS, we think, will spread to other geographies over time, or similar-type policies, but policies change. Market conditions change. The ability to optimize across the value chain to be the lowest and -- the most cost-competitive producer of these products, to access new markets that may -- where market conditions may be different. Last year, almost half of the product produced by REG was sold in the European markets, not in the California markets. All of that is really what will drive value over the long term. I don't have an answer for the cash flow question. I'd say the cash flow target we put out is in 2030. It is going to take time to generate material cash flow out of these businesses; more comfortable with where renewable fuel sits today, largely on the back of the REG acquisition. We expect more cash flow to come from these other businesses, but I don't have a point forecast for 2027. Eimear, you might talk about technology and renewable fuels.

Yes. We're focused on enabling feedstock flexibility while lowering costs and maximizing yields. So we think about the value chain. Maybe starting with feedstocks: We have a lot of technology efforts ongoing to expand the range of feedstocks beyond the oil that we've got experience with today. So we do a lot of feedstock testing in the lab. We assess feedstock. We test them. We qualify them. So we're focused on that aspect of the value chain and just expanding the set. When it moves to kind of the manufacturing part of the value chain, the hydro processing like pretreatment, we've got a lot of technology efforts there as well. And what we're trying to do physically is kind of design catalysts that will work at different operating conditions so, whatever gets thrown at them, they can manage. And they can manage higher temperatures and still secure the yields required, so that's flexibility. And we're using our expertise in catalysis, in hydroprocessing and in [ metallurgy ] to really develop a solution set there. So we have [ to care about ] the kit itself because of the different reactions also that go on. And then at the other end of the value chain, on the products side, our JV efforts with Cummins and some of the OEMs, we're testing these new products. So we are everywhere in the value chain when it comes to technology. What's been great with REG, bringing them into the family, is that they come with a lot of operational know-how. They have expertise in feedstock, procurement and supply chain. They have some pretreatment technology. And that -- marrying that with our expertise in catalysis, hydroprocessing and [ metallurgy ] is really allowing us to learn and have faster cycle times around trying some new things. We've got -- we're coprocessing today in El Segundo and we've got conversions planned this year as well. So that's how we are supporting the renewable fuels from both sides of the value chain and everything in-between.

Thanks, Eimear. Thanks, Doug. Next question, maybe in the back. Then we'll keep moving to this side of the room. I promise.

Neil Mehta here with Goldman Sachs. So my question is about the capital spending in low carbon as a percentage of the business. And where is it now? Where do you see it evolving over time? And then the follow-up is just can you contrast your low carbon strategy with who you view your peer set strategy is. And what do you think differentiates yours?

Yes. Thanks, Neil. On capital, we mentioned the guidance, the $10 billion over 8 years; no change to that guidance. The -- we've spent more, invested more in the renewable fuels part of the business, to start. There was a large inorganic component of that with the REG acquisition last year, but we see, we have line of sight to increase spending and to support our CCUS business and eventually our hydrogen business. And that's the way you can kind of think about these, and we'll continue to provide updated guidance as we go along. In terms of percentage of the overall enterprise, I'd let maybe Mike or Pierre speak to that. We go out and we've launched these businesses. We're talking to customers. We're trying to find the very best opportunities that both abate CO2 emissions, our own or third parties'; and also generate attractive returns. We'll be opportunity-driven in terms of the overall capital spend. There is an iteration that occurs with the overall enterprise in terms of what's the appropriate amount to allocate to these businesses. For right now, very comfortable with where we sit, but we're in the earliest days. We'll see where this progresses as we go forward year to year. On competitors. I'm not going to speak to any -- another competitor's strategy. I think there -- I think we feel like we have the right strategy here. We've been very careful about selecting businesses that we think are critical for net zero, so they'll see significant demand growth, but most importantly, we bring something of value to all of these businesses. And that's very important when we look at the opportunity set. If there's not a strong strategic fit for the company; and investing in a hydrogen project, a CCUS project; building a new renewable fuels facility, that's not something that we'll pursue. We'll be very disciplined in that. We're asked a lot about renewable power. We're not investing in renewable power on a stand-alone basis, but these businesses will require enormous amounts of renewable power, so how we partner to enable that renewable power is a core part of our strategy. So investing in that in a different way than some of our peers. And the last thing I'd say on the peers is there's certainly a competitive angle to all of this, but these markets are so large and growing so fast. And so important for the company, for the industry and for the world: Partnership but with our competitors, something we do each and every day in our traditional business, is a very important part of our success going forward, so we're rooting for our competitors to continue to make progress in this space. Because progress is absolutely what we need to make. Thank you, Neil, for the question. We'll go right up here. There's three right in the front, any order that you pick. Thank you.

It's Biraj Borkhataria, RBC. I have 2 questions. The first one is on hydrogen. Can you just talk to me about the economics in this space? Because there's a wide range of views out there on what role hydrogen will play, whether it's hard-to-abate or a wider role in different end users. But from your side, you're talking about shipping ammonia from Gulf Coast and West Coast to Asia and Europe. And to be frank: Every time I run the numbers, [ unless there's something I missed ], it's not even close to making economic sense, so can you help me understand how that can be competitive relative to other sources? And the second questions is on CCS and particularly for LNG, so a kind of 2-part question, but at Gorgon you've had some issues with not meeting your targets on CCS since startup. What makes an LNG project -- what are the characteristics of an LNG project that make it suitable for CCS versus others which are not? I'd just be interested to know.

Okay, yes, we'll hit both of those. There's a big technological angle on hydrogen, particularly transportation and storage, which is the highest-cost part of the value chain, so Eimear can speak to that. And we'll get into the latest on Gorgon as well, but look. I mean, in order to generate attractive returns in this space, these products have to be cost competitive. The numbers have to work. We're early in that journey. There are certain sectors in the hydrogen and ammonia space that we feel will work sooner; customers that will buy these products at the right cost, bearing that higher cost today, faster. And we're working with many of those companies in the world. I mentioned JERA in my opening remarks. Here is a very large energy company in Japan, great company, a long-term customer from an LNG standpoint, one of our most important LNG customers. They're very interested in decarbonizing that existing LNG value chain but looking. Is there a way to drop new low-carbon but related products like ammonia, like hydrogen into that value chain at the right cost to meet their lower carbon objectives? And those are -- they have high ambitions. They're challenging. It's a hard-to-abate country. They don't have the same renewables footprint. They don't have the same tools that you might have in the U.S., even Europe or elsewhere, so working with them on how we can produce ammonia, blue ammonia, using natural gas as a feedstock. We feel that's the lowest cost today. Transporting that ammonia to blend into some of their existing coal-fired power infrastructure. That's what we're trying to do. What policy support you need to make that new value chain a reality is something we're working through. We'll work the same. From a European perspective, it may be hydrogen to heavy-duty transport or hydrogen into natural gas-fired power or hydrogen for another use, but we feel, with the investment in technology, lowering the costs of delivering that hydrogen, with still the appropriate amount of policy support to start, we'll build this new energies system really and all of the infrastructure that's needed to make this business a reality. We're in the study phase now. We're doing a lot of different things, technology pilots and other things, but we'll be very cautious in making sure we marry the supply with actual demand from customers. Very prospective but still a lot of work to do in that space. You might talk about technology before we go to Gorgon and CCUS.

From a technology perspective in hydrogen, we're focused on 2 things: one, lowering the costs of hydrogen production; and two, lowering the costs of hydrogen transportation. So as Jeff talked about there's carrying hydrogen and ammonia, other fluids that hurry -- that carry hydrogen. So that's some of the technologies that really talk to the transportation challenge there. So we -- the way we look at this is we have a -- tech ventures, and we make investments in companies and learn from them. And this is an area where we've made a lot of investments, [ trade ] investments, over the last couple of years to look at some different technology solutions. One example is with Hydrogenious. And this is a company that has a liquid organic hydrogen carrier. So think about this liquid as carrying hydrogen to its destination, so you've got to put the hydrogen into the liquid, and then at the customer end, you've got to take the hydrogen out. And so we're not only studying how to put the hydrogen into the fluid but then release it at the customer end. The beauty of this type of technology that transports hydrogen safely in a stable form is that you can use existing infrastructure. You don't have to build new infrastructure. You can use existing ships. You can use existing pipelines, so that's why we're really interested in that. And JERA, who's a great partner of ours, we're doing a pilot with JERA to test this actually in L.A. and California just to see whether we can make it viable. So that's just one example in the transportation sector that we think offers promise to kind of unlock the constraint right now.

Great example. And on Gorgon CCUS, we -- first of all, Gorgon CCUS is one of the largest, most complex CCUS projects in the world; started up 3 years ago. We -- it is working. We've stored 7.5 million tons since startup in 2019. That is less than the planned capacity. We're working very hard to reach that planned capacity. There's a lot of lessons learned throughout this process that will actually be very, very valuable as we grow the CCUS business elsewhere. Maybe, Eimear, you can talk to some of the unique aspects of that or the technical aspects to give a little more color on the question.

Thanks, Jeff. So on Gorgon, when it comes to capturing the carbon and injecting the carbon into the reservoir, that's working. So that part of it is working. The challenges that we've had with the amount of carbon or CO2 that we've been able to put in the reservoir is more the water management system. So the reservoir that the CO2 goes into, we have to take water out to create the space for that CO2. And we've had constraints on the water side. So the water that we're taking out of the reservoir has -- it has particulates. It has to be processed. And it's we're constrained right now as to how much we can do, so the solution is to improve the [ surface ] equipment to handle the solids and the particulates and actually to pull more water out. And once we can pull more water out, we can put more CO2 in. So the CO2 is really working. The constraint is on the water management side, but what we have done with Gorgon is -- we have 4D seismic. We have fiber optic and data surveillance programs. We have modeled the reservoir and we feel that the CO2 is doing what it's supposed to do. Those learnings are the learnings that we will leverage as we look to subsequent assets where we would inject CO2. So all of that [ subsurface ] technology expertise, all of the surveillance expertise, all of the seismic expertise, all of that, we'll be able to leverage for growing new energy business.

Thanks, Eimear. Thank you for the question, yes.

Nitin Kumar from Mizuho. I have 2 questions. One, Eimear, you mentioned technology for improved recovery in shale. I hate to bring oil and gas into a low carbon discussion, but kind of curious. Just, one, is it primary? And two, we spent some time in the last session talking about getting Chevron back on its longer-term plan for the Permian. How much of that is being driven by this new technology? And how much of it is proprietary to you? So that's my first question. The second question, if we can unpack a little bit of that $8 billion of spending between technology and commercial opportunities. You've laid out some targets on CCUS, hydrogen, renewable diesel. You're not getting there for $8 billion, so I'm just trying to understand. What does $8 billion [ catch ] you, from where you are today, to those targets?

Thank you for the question. Do you want to take the...

Yes, I'll start with the shale and tight. And thank you for asking the question because technology is critical for our existing business today and to see if we deliver higher returns and lower carbon. So with shale and tight, so maybe I'll just maybe connect the previous discussion. I think, some of the things that we've learned in Permian around high -- fractures behave, how benches interact, how much communication there can be, a lot of that was actually discovered and informed by technology. So tracer technology, tracers that we put into the frac fluids, tracers that we put into the proppant that, when produced at surface, told us that we had these interactions and this interference, whether horizontal or vertical. So that surveillance program, which is constant, will be adjusted as we adjust our frac designs and on our well plans going forward. So that's just something that's part and parcel of normal business and learning high -- how the reservoir behaves. The recovery project is something different. And this is secondary recovery, so this is using, leveraging our expertise in advanced oil recovery to change the dynamics in the reservoir, right; and to change how the water and oil moves in the reservoir; and high -- and how the oil interacts with the rock. And adjusting that chemistry so that we can recover more oil. That's what I referred to in my remarks and we're doing that in a number of ways. So we are looking at advanced materials that we can inject into the reservoirs. That result in increased recovery. We're also looking at different stimulation techniques that we would couple with some of the chemical treatments that we're considering. And we've done a hundred pilots across the shale and tight asset classes. So not just in Permian, we've done some as well in the Rockies business unit. We've done some as well in the Canadian business unit. And all of those learnings together is informing a view that, we think, we can significantly increase recoveries without drilling but actually through a different means. So that's what we're studying. We're studying it in the lab, and we're studying it with our partners as well.

Thanks, Amy. It's fine to ask a lower carbon or an oil and gas question in a lower carbon session because one of the -- our lower carbon strategy is to lower the carbon intensity of our existing assets in the Permian is obviously getting a lot of attention, not just for that but for other reasons as well. And your second question, the capital guidance was consistent with the target. So those went together. It was heavier on renewable fuels on the front end. Of course, we added to that through the REG acquisition, but we're already halfway to our renewable fuels target at the end of the decade of 100,000 barrels of bio-based diesel. At the end of the decade, we're the second largest producer in the U.S. And that's before the Geismar project comes online a year or so from now. Carbon capture, I mentioned the Bayou Bend project, 1 billion tons of storage. I mean this is a very large size potential hub 5 million, 10 million tons per year, maybe even more. And the hydrogen projects we're looking at ammonia projects, I mentioned some of the -- how the demand could grow for ammonia. In the future, working with customers like JR, one of these facilities could be a larger size than the target that we put out, the 2030 target of 150,000 tons per year. We'll continue to update our capital guidance and these other targets. We won't chase the targets at the expense of value. We're going to be disciplined here, but we feel very comfortable with the progress we've made and comfortable with the capital guidance that we've provided. Thanks. I think do we have time for 1 more question. Last question, please. Thought there was 1 here.

John Royall from JPMorgan. Can you just talk about the opportunity set in sustainable aviation fuel. We've seen a couple of FIDs in that area. And I think the changes from the IRA make that business kind of more attractive. So where does SAF sit within your opportunity set, I think, more broadly and then maybe just on the renewable side?

Yes, it gets a lot of attention in the company, a big focus area. We're focused on hard to abate sectors. Transportation is a critical group of those sectors. We're also looking at power and industrial customers, I've given a couple of examples of that. But in heavy-duty transport, we're working every aspect of it. Trucking has been the lead from a renewable diesel standpoint or a biodiesel standpoint, we're seeing increased interest from rail operators, increased interest from marine operators and aviation is certainly the big kind of nut to crack in this space. It's more challenging, but you've got a set of customers that are in one of the hardest to abate sectors, very focused, very motivated to talk with us and others about how we can help them lower their carbon intensity and SAF sustainable aviation fuels is a big part of that. So when we look at our renewable fuels business, we're looking at how we can produce more of this product. If we can do so commercially, again, we need to be able to generate returns for the company. We're already producing some at El Segundo. We have the capacity to do it there. We're also looking at our Pascagoula refinery to produce more. And we're even looking at the Geismar facility, the REG legacy facility in Louisiana. Are there capital investments, which are more nominal capital investments we could make to significantly grow the SAF capacity out of that asset. The policy support is important, but even more important is getting to the right commercial agreements with the customers, in this case, the aviation industry. And we think we'll get there, but it will take time for that to develop. Thank you for the question. That is the last one, I appreciate everybody's interest in the company. Thank you very much for the questions. We'll now take a 10-minute break, and we will be followed in this room by Pierre and Mark. Thank you very much. [Break]

Hi, everyone, and welcome back. I'm Pierre Breber, and with me today is Mark Nelson. I'll provide a financial update, followed by Mark, who will close by tying together everything you've heard today. Investing efficiently in high-return projects moves the needle on return on capital employed. Over time, we expect to be a solid double-digit ROCE company at mid-cycle prices. And with our higher oil price exposure, Chevron is doing much better than that. delivering ROCE greater than 20% last year and leading the peer group in ROCE improvement over the past 5 years. Capital-efficient investments, combined with strong production growth, drive higher cash flows. And with CapEx guidance unchanged, we expect annual free cash flow growth greater than 10% at $60 Brent. Today, we're raising our share buyback guidance to $10 billion to $20 billion per year. The higher range is supported by 2 cases shown here and reflects our greater capital efficiency and low dividend breakeven. As we've said consistently, we intend to buy back shares across the commodity cycle, using surplus cash on our balance sheet and excess debt capacity to continue buybacks even when oil prices cycle down. If the Brent oil price decreases to $50 in 2025 and stay flat, Chevron is positioned to repurchase shares annually near the $10 billion end of the range. And in an upside price scenario with Brent increasing before settling at $70 in 2025, we could repurchase shares near the top end of the range. Commodity prices and margins are uncertain. Our approach to returning cash is not. We plan to repurchase shares across the cycle, acting neither pro nor countercyclically as we have over the past nearly 2 decades, buying back our shares $2 below market and at almost half the current price. Let me wrap up by restating our financial priorities. They're simple and long-standing; one, grow the dividend consistently, 6% annual growth over the past 15 years; two, invest capital efficiently to grow both traditional and new energies as Nigel and Jeff covered in their sessions; three, maintain a strong balance sheet. We finished last year with the lowest net debt ratio among our peers; four, repurchase shares steadily. Starting in the second quarter, we're raising our annual buyback rate to $17.5 billion. As the 2 charts show consistent and steady across the cycle delivers leading results. You've seen our past performance, we keep it straightforward and predictable, you know what to expect from us. I'll now turn it over to Mark to close.

Thank you, Pierre. Despite the market turbulence over the last several years, our objective has remained consistent to safely deliver higher returns and lower carbon. We expect to generate higher returns by investing in advantaged assets, maintaining capital discipline and driving productivity improvements. As Jeff laid out, we're focused on lowering the carbon intensity in our traditional business and continuing to grow new energy solutions. Our straightforward and pragmatic strategy, coupled with our talented people have enabled peer-leading results across the cycle. It's our consistent approach that generates the projects and opportunities highlighted today. This consistency drives value. We ranked at the top of our peer group in capital efficiency and lead in total cash return per share. We delivered across the cycle and expect to approach the future with the same philosophy. Our capital-efficient investments enabled the portfolio that made these superior cash returns possible. And the commitment to capital discipline is clear. We expect to grow profitably our traditional and lower carbon businesses without sacrificing gains in efficiencies, returns or free cash flow. Our track record speaks for itself, and we intend to continue to concentrate our investments on assets and technologies that deliver higher returns and lower carbon. To close, I'd like to reiterate our 3 main themes today. First, disciplined growth. We have confidence we will exceed our 3% production CAGR while maintaining capital spending within our long-standing guidance; two, lower carbon. With a focus on the critical energy, we deliver to customers and continuing to grow lower carbon energy solutions; and three, higher cash. We're raising our share buyback guidance range and rate. We expect to have the capacity to continue to return more cash to investors in the years to come. The future may be uncertain, but our strategy is proven, safely deliver higher returns, lower carbon. That's the winning combination. Let's move into Q&A. Please state your name, your company and limit to one question and a follow-up. Let's go to -- let's start with the Jeanine.

We've got 2 questions, if we may. The first one, it really just relates to your upside, downside slide. And we certainly appreciate that you're giving us a more realistic look on the price forecast that you're using in that scenario, higher in the beginning and then the 50% on the downside. Our first question is how different does the sources of cash look if you were to just use an even further down downside case and 150 through the whole case, particularly on the cash, the debt side of things. And then our second question is really on the breakeven. And can you just quantify, if possible, how that trends through the forecast period through 2027.

Thanks, Jeanine. So let me start with our financial priorities, and I'll just restate them real quickly. The first is to grow the dividend, and we've done that over the last 5 years twice, more than 2x our nearest peer. The second is to invest to grow both traditional, new energies. Our CapEx is up 30%. We kept our CapEx guidance unchanged. The third is to maintain a strong balance sheet. And then the fourth is to return cash to shareholders in the form of a steady buyback across the cycle. And so we increased our buyback range to $10 billion to $20 billion. We increased our rate to $17.5 billion. And when we do that, we're doing that with the intention of maintaining that for multiple years across the cycle. So what's going to happen over the next 5 years, none of us know. So we run different scenarios. You can assume our mid-cycle is in between, around $60 Brent, that's flat, and that's nominal. And then we have an upside case that gets -- ends up at $70 and a downside case that ends up at $50. The sources of cash first starts with our balance sheet. We -- at year-end, we had more than $17.5 billion of cash on our balance sheet. We can run the company at $5 billion. We don't want to hold that excess cash. We're doing that just temporarily. Over time, that cash will be returned to shareholders. That's $12 billion. There's $30 billion of that surplus cash. There's $30 billion of excess debt capacity. We've guided towards a net debt ratio of 20% to 25% through the cycle. We're at 3%. So that's a lot of excess debt capacity. And then we have a $50 breakeven notionally to cover our dividend and our CapEx. Well, the Brent all breakeven assumes everything else is constant, our breakeven last year was quite a bit lower than that because we had stronger refining margins, stronger natural gas pricing. So we're using the breakeven as sort of a mid-cycle on the other factors. And then we're going to generate free cash flow growth of more than 10% a year from Permian, Tengiz, Gulf of Mexico, other assets, petrochemicals. So as free cash flow growth increases our breakeven declines. Now we're going to grow our dividend and that goes the other direction. So yes, over time, our breakeven will go down. Now we could run a lower case and we have. We were the only company that showed a 2-year stress test at $30 Brent in the depths of COVID. So we can run lots of cases. We think going towards $50 is a reasonable downside case. In that downside case, we're buying near the low end of the range. We're buying $10 billion a year. $50 is our breakeven. So we're clearly doing that with the excess of the surplus cash and the excess debt capacity, I want to be clear that there are a lot of companies that have formulas to return cash to shareholders. By definition, those are pro-cyclical. If it's 30% of cash from ops or 50% of free cash flow, whatever it is, those were great on the way up when cash from ops and free cash flow are going up. They don't work so great on the way down. So what we're going to do is there will be a time, our cash return to shareholders will exceed 100% of free cash flow. That's how we do it because we're going to be taking off surplus cash and excess debt capacity. And if you went to $40, I think you know our sensitivities, it's $4 billion for each $10 change in Brent. So we're happy to run lots of other cases. We think that's a very reasonable case. And the only change from the prior year is we had 5 and 50. And when you're sitting at 80 or 100, it just seems like the first year or 2 just wasn't realistic, so we tried to give more realistic cases.

One of the -- I think, the hallmarks of the last couple of years for Chevron has been the focus on ROCE. So a couple of questions as it relates to that. Your confidence interval in terms of getting to the 12%. And then as you think about M&A, one of the challenges, even as you -- we were talking about Anadarko, it was -- M&A has a tendency to be ROCE dilutive because you mark-to-market asset immediately at this point of M&A. So just how does that factor into your decision-making as it relates to those investments?

I'll take the front end of that, and Pierre can close out on it. The advantage of having a mergers and acquisition conversation in today's environment is we don't need it. Our portfolio today, you think about the multiple growth assets that Pierre laid out of TCO, the Permian, other shale and tight maybe in the Gulf of Mexico, if you think about that portfolio, we do not need additions. That's exactly when you'd want to naturally be looking. Think about the actions that we have taken in the market, whether it's REG or the Noble acquisition, and we were able to do those at a time and in a structure that made sense for us and was useful for our shareholders. We'll continue to take that logic going forward. It's nice to be looking when you don't have to be buying and we'll continue to take advantage of that. The point I would reinforce is that we don't need it and that when we look at actions, they're value driven in this space.

We don't have bright lines on accretion. I mean Noble was accretive on all, which is fantastic. That's what you seek out. Anadarko, you're right. So we'll look for sure at earnings accretion, we'll look at cash flow accretion, free cash flow accretion. ROCE accretion is a nice thing to do. But it wouldn't stop us from doing a transaction. Again, there's no bright lines on that. We'll look at the totality of the quality of the assets, the strategic fit. Of course, there's got to be something in it for our shareholders the doability, and we'll look at a variety of metrics. And you're absolutely right, that's one of the toughest ones. But we've shown we can do that too.

Doug Leggate from Bank of America. Cash CapEx, Pierre, I wonder, if knows every topic that you've periodically given us guidance on. So as Tengiz rolls off, and I think Mike had alluded to maybe another $1 billion available for capital. Can you just walk us through what the moving parts are in the cash CapEx? And I've got a follow-up, please.

So our current budget on CapEx, and we changed our nomenclature to CapEx and affiliate CapEx. It conforms with most others do it. And so the consolidated company CapEx is $14 billion. Our guidance is $13 billion to $15 billion. So there's $1 billion of range to move up, as our affiliate CapEx goes from $3 billion to $2 billion. So we're still within the $17 billion combined number that we've been talking about. And that $1 billion is largely more activity. It's more activity in the Permian. It's more activity in shale and tight and there's some other puts and takes. So we'll announce our annual CapEx budget in December for the next year. This year, we're at $14 billion. There's no change in that. We affirmed that long-term guidance, and there's $1 billion of space that's still going. It could be absorbed by some inflation, but a lot of -- right now, the plans are that it's primarily increased activity in Permian and other shale and tight.

Yes. If I could add -- the piece that I would reinforce is what that capital discipline on this portfolio has delivered over last 5 years. I mean, you look at how we beat our competition in cash return to shareholders. You look at the leading capital efficiency and return on capital employed performance. Those -- that's a combination of this capital discipline and the portfolio together. You have a second follow-up?

Yes. My follow-up, and it's kind of a bit of a self-serving question, so I apologize. Mike also alluded to or mentioned the possibility of significant expansion of your LNG portfolio towards the end of the decade. And I noticed you're using in your assumptions to 450 average Henry Hub gas prices, which apart from 2022. I don't think we've seen that in quite a long time. So when you think about the big picture, LNG growth, LNG expansion, 450 gas and you look at the valuations of some of the U.S. gas equities. How do you think about your portfolio ability to leverage that LNG opportunity? I guess it's an M&A question.

Yes. So I think I'll address the context that Mike was creating first and you can tag on here, Pierre. Our gas portfolio is Pacific Basin leveraged in Pacific Basin focused that's with our associated gas out of the United States and our strong position in Australia. We've begun to increase our exposure to Europe, but the structure is to be Pacific basin weighted and have growing exposure to Europe. We've taken actions. Clearly, we've got our U.S. Gulf Coast offtakes that will come towards the latter part of the decade. We have a strong West Africa position that we're keeping full and effective. And then, of course, we have our Eastern Mediterranean piece, which I think was what Mike was alluding to in regard to Leviathan asset in and of itself and making decisions about what we do with that very large gas offshore low-carbon resource. And that decision, although likely made from a design standpoint this year that won't come to market until later in the year. But our portfolio will continue to be Pacific Basin weighted. Gas prices in the U.S. obviously, have come down quite a bit, but we like our portfolio today.

Yes, just to address it. I mean it's a 2027 assumption. So we'll see -- it's been a very warm winter and obviously price oversupplied. We've said no structural change in oil, right? $60 are our mid-cycle 2027 assumption, no structural change in refined products. We have said with the war in Ukraine and the EU reducing Russian supplies those molecules aren't finding their way into the market. There's going to be more LNG exports. We position ourselves with offtake agreements, but that will be a pull on Henry Hub prices. So it's a modest increase from where we were prior year, it reflects what we think is going to be likely in 5 years, a little tighter pull on Henry Hub and really mostly for exports to European markets.

Yes. Long term, we believe in Asia, Asia strength. Let's go to over here, Biraj?

Biraj Borkhataria, obviously. So 2 questions. The first one is on a small change to the deck. Last year, you talked about 10% CFFO CAGR. This year is free cash flow, which makes life a little bit more tricky. But could you just help me understand if there's any changes in I know affiliate CapEx has moved down, so that flatters the free cash flow. Just a bit of color around that would be helpful. And then secondly, on the dividend, if I'm thinking about 3% production CAGR with margin accretion, which is what you're going to plus buying back to your 3 to 6 on share capital each year. that kind of points me to dividend growth rate over the medium term around 10% per annum, obviously, subject to price. I'm not expecting guidance, but am I thinking about those moving parts the right way and the buyback linking to DPS growth.

Sorry, what was the number you said that led you to what number?

10%.

So let's see, on free cash flow versus cash from ops, I wouldn't read a lot too. We've gone back and forth a little bit that's how the numbers shake out. I think we're going to stick with free cash flow. It says it makes your life more complicated, but I think it's most meaningful to investors because it's what's available to investors after we go through it. We've done it per share. Now we just decided to do an absolute free cash flow. And then, obviously, the share count is decreasing significantly in these scenarios with the buybacks. Let me take the tip then you can add, Mark, to either one of these. So Yes, you got 3% production growth. We've got -- we talked about reducing OpEx per barrel 10% by 2026 at mid-cycle conditions. You've got margin expansion. You've got the shift in how we're investing our capital, so we're much more efficient in capital investments. So all of that says that's where you get the 10% free cash flow growth. So I mean that's what is our ability to grow the dividend clearly and do it in a sustainable basis. Now some of that is TCO, right, coming back after a number of years of investment. So when we think about dividend increases, we're thinking about an increase in perpetuity, right? We have to have confidence that we're going to be able to -- just like we have grown it for 36 years, not cut it since the depression. When we think about share buybacks, we're thinking about over the cycle. We got this question on the fourth quarter call. We're not trying to manage an absolute dividend burden. We're also not trying to manage a share count. The buyback is a way to return cash to shareholders over a cycle, that's excess to the first 3 priorities. The dividend is returning cash forever. That's how we view it. And so they're just operating on different time lines. But you're right, if you put all the accretion from the buybacks and the free cash flow and TCO coming on, you can get to higher numbers. That's a decision for our Board. We stand by our track record, 36 years of growing dividends. 6% CAGR over the past 15 years, a 5-year dividend growth twice our nearest peer, and we're doing that in addition to significant buybacks.

Sam Margolin, Wolfe Research. Inflation is a hot topic, and it is particularly important to your program because everything kind of fits together like a puzzle, right? And inflation can really be a grenade in that. And so the question is, tying back to the margin expansion slide from the first panel and then the free cash flow growth targets. A lot of that's driven by mix shift. Shale, Gulf of Mexico, higher margin than some of these conventional [barrels] that are rolling off. And so the question is, is there any tension or friction? Is there an inflation point where some of the mix shift gets threatened, where it changes. It's cheaper to stem decline in conventional than it is to start new projects. And so the question is that is there any inflation risk to the margin expansion targets on the basis of projects moving out of the stack?

Yes. Thanks, Sam. If you step back, let's talk about what's been built into our plan first. So you have that foundation. I mean inflation is always an opportunity for us. Today, we have built inflation into our 2023 capital at that 5% to 7% range for the entire portfolio and then, let's say, low double digits for the Permian. So that's built into our capital plan today, recognizing that because we have such a portfolio in the Permian, we're able to go out and get our contracts for wells and services and things like that out not just through 2023, but into well into 2024. We feel comfortable with the current balance today. The mix we have from a portfolio standpoint is completely intentional. The returns in the Permian are so competitive that your premise that it's easier to do base decline, which is only 2% in our current portfolio. I might challenge that a little bit. I mean these channel type resources are very competitive. So our ability to stay within our capital forecast while increasing activity is built into the current plan, but it is something we'll have to watch as if inflation continues, it's something that we can test over time.

And the best proof point, the Permian had the highest inflation last year in the industry. Jay Johnson showed this on the second quarter, you'll see it in our proxy coming out. Our cost to develop for [ EUR ] expected ultimate recovery stayed at $8 a barrel last year, which is the same as it was in 2021 in a different inflationary environment. So not saying we can do that every single year. There's how we procure for goods and services, and I think we do that better than others. There's -- what we do with those goods and services, how efficient are we with them. And then -- and we're working really hard to offset it. But yes, if we see sustained high inflation rates, which we're already seeing some things moderate at this point in time. And I'd also say, I don't think there's a structural change in the service company industry. We are seeing -- it's near capacity, right? Rigs are near capacity, sands are near capacity, lots of things. So you'd expect prices and margins to reflect that. We can add a rig that's not current in service by refurbishing, paying for that and doing a little longer-term contract. In our fleet, that's a very manageable thing to do. So I think we have a lot of tools to manage inflation. But if we saw sustained high inflation, then, of course, that at some point in time, we could revise our CapEx guidance.

Yes. I don't know if you had chance to ask Eimear this question, but the application of technology in the business continues to provide dividends. And from my perspective, learning a bit more about what we can do with new frac fluid or fiber optics in the shale and tight in and of itself creating significantly more recovery on the current activity we're doing today. Those are things that we will continue to lean forward on that. When you go on a unit basis, we may be able to offset the pressures that we're experiencing.

Nitin Kumar from Mizuho. I want to pick up on that last point. You just said, so this technology that improves your recovery, let's for assumption's sake, you have 50% better recovery for 10% more CapEx. What do you do in that scenario? Do you keep your activity levels the same? Or do you grow faster?

Well, our standpoint, remember, was the return-based decisions. So production for us is an outcome and always has been an outcome. And with that in mind, you've seen 3% CAGR that -- where we have considerable confidence in our ability to deliver that. Today, we would say return that we don't need to grow faster. We just need to continue to get the highest returns to the business. So I think we would -- today, we would stay within our capital guidance and continue to get more efficient.

The objective is to grow the company with the least amount of capital. We're not a growth investment. We attract dividend of PMs, value investors, increasingly some growth at a reasonable price. Our 3% growth, I mean, you can do the math, we're showing more than that. we want to have high confidence in our ability to deliver on it. But we're not going to -- yes, if we can deliver these business results with less capital, that's what we're going to do. We're much more capital efficient when we we've seen the other movie that was 10 years ago, where we maximized capital and didn't grow even at these rates when all was then done. And we lost investors. We're working hard to win investors back to energy. We made some progress last year. We still have a long way to go. And it's this consistent quarter in, quarter out showing capital discipline, working hard to have efficiency that offsets inflation using technology to improve returns. And if we can grow 3%, find margin expansion, a couple of other percent here and there and have reasonable prices. You can see that we're a very attractive investment. There's a lot of upside left where 5% of the earnings of the S&P 500 -- sorry, yes, 5% of S&P 500 by market cap were more 10% by earnings and cash flow. So we still have a lot of upside with investors. But we've got to show it quarter in, quarter out and grow at reasonable rates and do with the least amount of capital. And that's the mindset shift that you've seen is a portfolio shift, but there's really a mindset shift. Our engineers are how do we get this project done with less capital because if not, they're not going to get the capital. The bar is set really high. The Permian sets a high bar, other shale and tight, even how we're doing Gulf of Mexico is very different. We used to do sort of custom designs and size it to maximize initial production to other size in a standard way, longer plateau. So there's a lot of actions that we're taking to improve capital efficiency. It's all about winning investors back to energy. It's their capital. We need to be really wise with it, and we are.

You have a follow-up or you're good?

Do I get a follow-up?

You may have a follow-up.

Sorry, I don't want to -- I'm not going to hold this.

Top performance based, but go ahead.

Sure. So Mike said in an earlier question that if he thinks we're at the highs of a commodity cycle right now. Today, you're leaning into your buyback where you just said you want to be countercyclical, not pro-cyclical. So could you sum that up for us? What is your -- I won't hold nice comment against you, but if you want to talk about your macro view and then the decision to lean into the share buyback pace starting in the second quarter?

Well, let me start, and Mark can add. So the buyback guidance is a sign of confidence in the company's ability to generate surplus cash to those first 3 priorities. And so it's because of more capital efficient. It does reflect what looks like more of an upside case over the next several years. But we have the range, and we intend to use it. But again, we're not trying to be countercyclical. We're trying to be across the cycle and we're trying not to be pro-cyclical. And I think most of the various cash returns to shareholders are pro-cyclical, variable royalties, special dividends. It all works great in the up cycle. What do investors get in the down cycle? What investors get in the down cycle with Chevron is, of course, the dividend that will continue to grow, right? It grew through COVID, and you'll get that steady buyback even in those out years. So we're setting it at a level that we can maintain it across a number of years. Commodity prices and margins are going to bounce up and down. And we're just going to set at a level that we have confidence that we can maintain it for multiple years.

Yes. And I just want to build on the confidence in that 10% free cash flow growth that we talked about earlier. The growth assets that we have today, I mean, is the Gulf of Mexico, it's the Permian, it's TCO, it's other shale and tight. It will be the petrochemical crackers that come on in the second half of the decade. Those are multiple assets that will drive cash, including our renewable fuels business. I mean, these are all things that are incremental to conversations over the last couple of years that just give us high confidence in that.

And just to put a point on it, that's all at 60, right? So that free cash flow growth, obviously, at 70 is even higher.

Paul Cheng, Scotiabank. Two questions, please. I have to apologize. I want to go back into the buyback. I think in your high and no case, we need the distention is by 2025 and forward, whether you see $70 plus or do you see $50, right? So between now and then, what may trigger the change in your buyback pace from currently 17.5 to higher into 20 or lower back to 15 or maybe below, what may be the trigger point?

Well, I'll start and you jump in. I mean, look, it's an uncertain world. We know China is reopening. We don't know exactly how that's going to show up. We have the central banks tightening interest rates. We had a strong PCE number on Friday running hotter than people expected. So we could have a hard landing, we could have a soft landing. It's a cyclical business, Paul. You know that. We've been in it a long time. Prices go up and down. So there are a lot of factors that could drive it. And so we're just doing our best case of where we see the next several years going, and we're setting at that level. We're keeping the range. We reserve the right to change it. We worked our way up to this level as we got greater confidence in what we think is a sustained recovery. The supply side and then there obviously on the supply side. So it's all the factors that you normally track and but they're uncertain, and the future is uncertain. And so we have a range of scenarios and we have a range on the buyback. But again, we could have a much bigger buyback right now, but that would be pro-cyclical. We're sitting at a level with the best of knowledge that we have of an uncertain future of how we can maintain it steadily or keep it steady across the cycle.

Yes. I would just reinforce the uncertainties. If I had to pick the biggest uncertainty we were talking about this earlier this morning in some of us. The idea China is reopening and whether that's a straight line in regard to energy demand or a bit more up and down as they get through opening from post-pandemic. And then when you think of the resolute approach of OPEC today and the E&Ps and their capital discipline that keeps supply in a fairly steady space today. And then you have the uncertainty of Russia and the economy that Pierre mentioned. In a year of what I would consider uncertainty, the one thing that is certain is our ability to deliver on the 4 financial priorities.

The second question, maybe I want to talk about the -- as a gatekeeper, how you decide whether the project will be acceptable return and then you will go ahead like, for example, I mean, 10 because of the characteristic that the free cash flow, once that they come on stream is big and there's really very long duration that you can note. So I think at the time when you sense on the project, you are set a lower return. I mean even without the cost overrun that the return will be low. So if I look at the new business venture, based on the characteristic and also that to some degree that you are earning your social license, how those return criteria will be different than your traditional oil and gas business. I mean, are you willing to accept a lower return than you thought? What is the minimum that you need in order for you to say, yes, you get to go ahead and be able to proceed with those.

Thank you, Paul. If you think back to our energy transition spotlight, we made it very clear that our expectation was that our new energy businesses would compete on return on capital employed and returns themselves. And so you step back and you think, okay, these are emerging businesses, what does that look like in the short term. When we make our capital allocation decisions today, it's a mix of our strategy and in a portfolio return basis. So the strategies of each parts of our business, we have expectations of what they need to be funded to grow and to sustain and then we do it on a returns basis of that mix. So your comment about making investments in things that will be longer standing, meaning they take larger projects, we will still have to make those decisions as a corporation. But from a renewable fuel standpoint, let's talk about the new energies businesses that are available today. Those -- the returns in the renewable business, renewable fuels business are competitive today. And that's a part of the portfolio that, of course, started to grow in new energies sooner. Today, we're the second largest bio-based diesel supplier and marketer in the United States, one of the largest in the world. That's in addition to our activity that we did with the Bunge joint venture and our recent acquisition of the remaining shares of Beyond6 in the compressed natural gas space. All of those returns compete is predominantly because the customer can use it today in what they have. And so it makes sense that, that would come first in the evolution of our new energy businesses. When you're building a CCUS business you want to start more thoughtfully because there's an issue of building an entire value chain that's necessary. So today, the place that you would expect us to start and I suspect that Jeff talked about this earlier, the first place you'd go is acquiring pore space in a place where you think you will need it over time. And we are doing a very good job of that today. On the hydrogen side of the equation, you're likely going to follow the natural gas value chain, which are going to be very careful until you can figure out how to transport gas and make it economic. And that's why you're seeing those more back-end loaded. But we are well on pace to our $1 billion of cash flow from operations for our New Energies business, driven by the part that can deliver those returns today, which is renewable fuels.

Yes. I'll just go to the traditional business. And we've always had more projects in the upstream than we would fund. I mean we're trying to fund obviously well above the cost of capital. But I'd say 30-plus years in the company, that spread is higher than it's ever been. And the only way to get return on capital employed up to 12% at 60. Now we were above that last year, but if you're at 60 is by investing in projects well above your cost of capital. We have those, and that creates more competition for engineers to get the returns up, which means you got to use less capital. So this is all about, again, how you invest less capital to achieve your business objective. And I think we're just seeing and it's a mindset change. And look, it was forced on us in some ways by the market. When you're in an underperforming sector, for 10 years, you've got to change the game. You've got to change the outcome. We have changed it. And I think it's underappreciated how much more capital efficient we are. We can sustain and grow this enterprise at $14 billion CapEx at rates higher than we could grow when we were doing twice that CapEx. And that's what we have to get and connect with investors. These are a different company. We're a different company, where it's a different portfolio. You can see our results quarterly because a lot of it is short cycle. And I think as you see quarter in, quarter out that it takes this capital -- amount of capital to grow cash flows, I think we'll get more investors back to energy.

[Indiscernible] focus on that. So we assume that the minimum refinement for your new [indiscernible].

You should not assume that. It's a function of Permian is 30%. So as you know, we're managing a portfolio of businesses. We talked about inorganic, which are different characteristics. But you should assume that we're going to get to 12% at $60, and we'll find lots of ways to do that. Thanks, Paul.

It's Lucas Herrmann at Exane BNP. Sorry, this is probably detailed rather than structural and framework. Two, if I might. The first is just Australia, PRRT. Are you there yet? Are you paying PRRT, et cetera. And the second was just what the tax position around TCO is as well going forward? I mean, clearly, you've been investing very heavily I would presume there's been a benefit of allowances as a consequence in terms of the cash generated and effectively returned to you. Again, it's a question on taxation, et cetera, in that region, that's it.

Thanks, Lucas. So we did a full tax transparency report in Australia. I encourage you to review it. It's part of the stakeholder engagement. We are -- I believe -- I'm not 100% sure, but I believe we're not yet paying PRRT, but we will one day, and it depends on future prices as you'd expect. But there's full tax transparency in Australia, which has -- I mean PRRT is essentially like a windfall profit tax or it's when your returns get to a certain level, you pay additional taxes. So it's built into the tax code. It's of interest to stakeholders, and we're sharing full transparency on that. On Tengiz, it's an affiliate, right? So it's going to have its tax return in Kazakhstan. You're right that there were some tax benefits that were accruing as we were constructing it. And again, there's the 15% withholding tax, which is what you really see when we receive the dividend. So the tax benefits are kind of part of the cash flow within Tengiz, which is a separate company. And then again, what we receive as a shareholder is the dividend. And we've shown that we expect that free cash flow to grow to $5 billion at $60 Brent, and that will come back. Some of that -- that's our share that will come back to Chevron in the form of higher dividends. and debt repayment. We have about $4.5 billion of debt that will be repaid over that time, and that will be a different part of the cash flow statement.

Sorry, just following up on the PRRT point. you've got an assumption on price. You've got an assumption on volume, you've got an assumption on cash flow in terms of Australia. So at what point do you actually start paying?

That's not something I'm going to disclose because those are all uncertain and it's going to be when all those things play out, and there's a very rigorous approach with the tax authorities, and it's based on the actual return. So it's not something that it's even we're speculating about it. It will happen when it happens at that point in time and it will kick in. Thanks, Lucas.

Jason Gabelman from Cowen. Two quick ones on the financial outlook. Just going back to Biraj's question and trying to tie last year's guidance to this one, to be clear, was there any change to your cash flow from ops outlook? Because it does seem like it's a touch lower. I think if you do the math, our math, at least it was $32 billion of CFO in 2026. Is that the -- I don't know if that number is right, but in terms of your outlook hasn't changed at all. And then secondly, on CapEx, I know it's a tight range of $15 billion to $17 billion. But based on the environment we're in today, thinking about inflation potentially staying high, is it fair to assume the CapEx continues to come in at the high end of the range over the plan period.

On the second question, yes, you should assume that we're trending towards the high end of the range. Look, it's a good part of the cycle. So the bottom end of the range which we went actually below reflected a tougher time in the cycle. So yes, you should expect, as I said to the earlier question, more activity in the Permian, more activity in other shale and tight, you should see us trend towards the high end of the range. And as you said, we have inflation. I think I'll take your detailed cash from ops question off-line and working with Roderick. We are not trying to move anything around. We are doing free cash flow. It's very simple. The free cash flow growth comes from Tengiz, Permian, Gulf of Mexico, some petrochemicals, Geismar expansion. I think it's pretty transparent. We have some assumptions that we put in there that -- so some are higher, right? Our gas price, we talked about that is higher, international LNG prices higher. So there's some puts and takes in that, but I think we can reconcile all that probably off-line.

John Royall from JPMorgan. So just thinking about your dividend growth versus your free cash flow growth, assuming you stay with a 6% or so pace on the dividend growth, you're growing free cash flow by 10%. You throw in reducing share count with the buybacks to dividends, in total dollars will be less than 6% growth. So is that a case for potentially accelerating the pace of dividend growth? And I realize it's a board decision, but conceptually, it would seem that with 10% structural free cash flow growth at a flat price you could probably accelerate there more on a sustainable basis. So just the pacing of the dividend relative to free cash flow growth, and I guess it gets into dividend versus buyback.

Well, I'd just go back to, I think, Paul, was your question about uncertainties. If you can help us confirm China's recovery and demand, and then what will happen with Russia and Ukraine and then interest rates in recession, it might be easier to answer the question. But the reality is we're designing to do this through the cycles.

We intend to have a leading dividend growth, and we've had leading dividend growth. For 5 years, we've been twice our nearest peer. That means there are 2 -- 3 other peers who are even further from us, and I think we know what a lot in the industry did. We protected the dividend. We showed the 2-year stress test at $30. So our investors knew their dividend was safe. We increased it actually 8% right before COVID, 4% through COVID and then 6% earlier this year. So we have to look at a lot of measures. Our free cash flow growth is absolutely part of it. Now some of that is tied to TCO and the lower -- the high investment levels that we've done. So we have to factor all that in. We have to make a recommendation to the board. But I want to be very clear. We intend to lead in dividend growth, and we have. We want to keep all of our portfolio managers who are focused on the dividend very happy. And then on the other hand, we're trying to attract growth investors and value investors and others. And so we really have a balanced approach. And we got to look at our competitors, other uses of cash and everything that you'd factor into it. So free cash flow is a good indicator of our confidence in continuing to lead in dividend growth. I wouldn't try to infer any specific number, and it's really not a decision for us. It's a decision for our Board, as you say.

And then second question is maybe more housekeeping and if it's too detailed, happy to take it offline. When you talk about the breakevens being quite a bit lower than $50 per barrel in '22, just to confirm, you're only flexing the oil price there and the downstream margins are staying the same. Because looking at Slide 31, when you normalize everything, it looks like $10 [billion] of free cash flow is actually below the dividend at $60. So when you talk about the $50 notional kind of what are the downstream assumptions there?

So what I meant -- what I said and make sure I understood is that if you use actual margins in 2022 and actual gas prices. So it's an oil breakeven. So you're calculating for the oil price, but you're letting everything flow. So our actual '22 breakeven was well below $50. Now if we normalize '22, which I think is what you're doing in the math, and you go to mid-cycle margins for natural gas and mid-cycle prices of natural gas, mid-cycle margins for downstream. Obviously, then you're going to be closer to that $50. And it bounces around. So we use $50 as a notional number, and we can take you through all the numbers. But I was referring to our actual '22 breakeven. Oil breakeven was much lower because other parts of the business were above mid-cycle.

Ryan Todd at Piper Sandler. A question on the downstream investment at Pasadena and the expansion that you have going on there. Is that more of a function of coordinating with your Permian growth outlook that you have there? Or does that infer a certain view on the downstream margin environment going forward?

Well, I think take all the way back. I think we might be the only company who have purchased a refinery in the not-too-distant past. But the logic in the acquisition itself was to really serve 3 value chains: One was 2 refineries together in the U.S. Gulf Coast, Pascagoula and Pasadena refinery because you can trade intermediates and scheduled turnarounds and things like that. We also have the ability to place our own product in those markets, which we were serving today. So putting our own refined product into the local markets rather than trading for them, if you will. And then the third, perhaps most important, was the ability to place our Permian production into that particular facility. The investment in it's a relatively small investment, but the investment in Pasadena is so that we can produce more of our Permian production through that particular facility, taking it up to 115,000 barrels a day, and it will be a good return project.

It was always envisioned as part of the transaction. So when we acquired Pasadena, it was with the intent down the road to do this modest investment to have it fit the Permian.

We wanted to operate it long enough to make sure we knew how to do the investment with confidence. That's what we have done.

Devin McDermott with Morgan Stanley. I just have a quick one. Pierre you mentioned 10% OpEx reduction over the forecast period, and you all have been, I think, very good versus peers and being ahead of the curve and cutting costs out of the business, driving efficiencies. Can you talk a little bit more about what's driving that? Is that mix shift across the assets? Or are there more cost cutting and efficiency opportunities that you have in the plan?

So yes, some of it is mix shift. Some of it's growing barrels in areas where we already operate. We're going to have more barrels in the Permian, more barrels in Tengiz, even Gulf of Mexico. We transformed our organization, different ways of working, digital, I mean all of that. So now it's sort of a mid-cycle because you have transportation, you won't see that so much in 2022. But as we look out to 2026, we stand by that guidance, and we're working hard towards that guidance.

A quick detailed question, but are you guiding to disposals still?

The guidance for this year is up to $1 billion. So the only assets in the public domain are interest in Alaska and Myanmar, which we've talked about previously.

And we've historically averaged about $2 billion, we'll continue to high-grade the portfolio over time. But as Pierre said, it's under $1 billion for this calendar year.

I apologize for the follow-up. I just wanted to take a little bit of math. So the 10% CAGR of just eyeballing the chart actually looks more closer to a 15% CAGR. Is that right?

It's higher than 10%. It's greater than 10%.

On cash flow then, that's about a 5% CAGR. Is that right? 27% goes to 37 to 17...

Yes. It's about $10 billion of free cash flow -- absolute free cash flow growth.

So 15% CAGR on free cash flow.

I'm not going to -- we like to keep a little something. We like to give guidance that we deliver on. And so we show you kind of the numbers, same thing on production, but we're going to focus on 10% because things happen. But yes, you can look at the math, and it's higher than that. It's about $10 billion. You can get $4 billion from TCO, you get $3 billion from Permian, you get $1.5 billion to $2 billion from Gulf of Mexico, Geismar, Petchem, you add it up, it's pretty straightforward, self-help in there too.

Since the confidence.

The reason I ask for the clarification is, it's a dividend question, right? So it looks like the cash flow growth then is about 5% CAGR. How do you think about dividend coverage as we think to try and gauge what your dividend growth could look like in absolute terms?

When we engage with our board to John's earlier question, we look at a variety of measures. What I can say and then Mark can add to this, we're a better company than we've ever been. We look at the 2000s was maybe was when we were winning investors. And if you look at our CapEx efficiency, so we look at CapEx to cash from ops, we look across a number of metrics, it really looks like the early 2000s. It looks like the time period when we went from 5% of the S&P 500 to 10%, when we were still capital and cost disciplined before the industry started investing further. So all those metrics are very favorable. So if you look at them, I think this is John's question, you could argue your way to higher dividend growth. Those are the kinds of discussions that we have internally. We need to have confidence in the sustainability of it. Again, a dividend increase is in perpetuity. The share buybacks, which, by the way, are at record high rates also reflects confidence across the cycle, both reflect a lot of confidence as we get more and more confidence that we can sustain those dividend increases in perpetuity, then you're right, you're seeing a portfolio that has the capacity to do more. We also have to look at the competitiveness, what are others doing. So there's a lot of factors that go into it. But the takeaway is we're a much better company than we have been, and we have a lot of confidence in our ability to deliver on our guidance.

Yes. And I would just build on the confidence theme. When you have a portfolio that has multiple growth assets that we have and this leading capital efficiency. Those things together allow us to continue to be this far ahead of our competition on these key financial metrics. And you can see that in the numbers that we've presented. I wanted to say thank you. It is fantastic to see you all in person and for the as usual, the thoughtful questions. Certainly, appreciate your interest in Chevron, and I just want to say thank you again. We will continue engaging as we always do to get more feedback and to continue to drive the company to a better place. But thank you again for joining us. It's great to be with you all.