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 three sections, starting with higher returns, followed by lower carbon, closing with winning combination. In each sections, our executives will lead with brief comments, a few slides, reserving most of the time for Q&A with sell-side analysts. We'll have two 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 risk, 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.
Well, thanks, Roderick, 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. Through 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 and 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 a half a billion dollars 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 billion dollars. 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 onto 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 five years, we expect unit upstream earnings to increase over 50% at flat prices. At the same time, we have confidence in exceeding our five-year annual production growth guidance of over 3%, led by the Permian, Tengiz, Gulf of Mexico, and other shale and type 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, the 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 perform completion activities on four wells at the same time, and optimized gas lift, which lowers downtime, minimizes workovers, and improves safety. This year, we'll be running four grid-powered rigs and one 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 startup 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 field decline by converting the field 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 hull. 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 three of our key deepwater leases and will 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 cargos in 2022 as Gorgon and Wheatstone together delivered first quartile reliability. The Gorgon phase II project is expected to be ready for startup 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 Nargis 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 advantage 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 and 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 tail 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 advantage 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 fuels 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. Sam was quick on the move over here, so we'll start over on this side with Sam.
Morning. Sam Margolin at Wolfe Research. Thanks for taking the question. 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. 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. Chevron's made macro commentary in the past. There's plenty of resource in the world. This is a dislocation that seems like it would be an opportune time for M&A, and especially since you have no debt. I guess framed that way, how are we thinking about M&A right now?
Well, Sam, you probably won't be surprised I'm gonna give you a high-level general answer here. Look, I think we've got a track record in M&A that speaks for itself. We've done well-timed deals over more than the time I've been in this role, over many decades before, to grow the company. I think our, you know, proficiency there has been one of the keys that's made us a survivor and one of the strongest companies in the world today. 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. They get run through a set of filters on asset quality, strategic fit, value, willingness to transact, et cetera. We know what companies we like. We know what 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. 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.
You know, the history books aren't filled with great deals that were done relatively high in the commodity price cycle. I would argue that we're relatively high in the commodity price cycle right now. Valuations have recovered. Companies are proud of their assets. I'm not sure that, you know, now is the time you're gonna see a lot of deals done. It is still an industry that is highly fragmented. You know, we're one of the biggest companies in this industry, and we've got a 2% market share of the global oil market. There is room for consolidation in different parts of the value chain, different parts of the world. We'll look for the opportunities that we think make sense and create value.
I can see you've got a follow-up question on your, 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 know, you have, you had the dot plot on the Haynesville. Prices have been inviting and then disinviting activity there throughout the past 12 months. There's an LNG option value too.
Mm-hmm.
you know, how do you think about your natural gas position in the U.S., the structural gas story in the world, and then, you know, how to commercialize it, internationally.
Yeah. I'm gonna let Nigel 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. 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've added a rig line in the Haynesville. I would say that's not driven by short-term pricing. It's driven by long-term fundamentals on the outlook on the market. It ties to the LNG position that we've taken for offtake on the Gulf Coast. We've got a nice growing LNG, natural gas position around the world that allows us to combine into a portfolio that can have flexibility to either access Asia or Europe. 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 up to complement what's already in Australia, and West Africa. We have 20 TCF of resource in West Africa.
We have two offtake positions there. Potentially towards the end of the decade, there's the option to add expansion in the Eastern Med 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.
Good morning. Nitin Kumar with Mizuho Securities. I wanna maybe unpack the Permian DUC issue that you noted in the Delaware Basin. Your solution seems to be move to single-bench development to go back on track to your development plans. What I really wanna try and understand is, was this a communication issue between zones as the solution seems to suggest? If so, when will you be going back to those zones, and what do you expect to see at that point?
Yeah. Let me take a first crack at that, then I'll have Nigel get down into some of the specifics relative to go-forward plans. I hope you noticed that the headline is our production guidance is unchanged. 3% compound annual growth rate over the next five years. Permian, 1 million barrels a day by 2025, 1.2 million plateau later in the decade. 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, then you've got sub-basins within each of those, 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. We highlighted some of the elements of the go-forward plan that we have a lot of confidence in, but we learn every year, we evolve every year. Some years, those learnings are maybe more evident to you, but they're always going on. This is the case again, you know, as we look at the learnings over the past 12 months. Maybe you can talk specifically about some of the basin learnings, Nigel.
Yeah, Mike, thanks for clarifying the guidance. Our production is a function, our production target is really a function of our capital and cost discipline. There's a slide in the appendix I think is worth taking note of. As I think about our production goals in the Permian, I really think about them in three 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 mineral interest in a large acreage position, which is a strong competitive advantage. We have our energy JV program, which, where we partner and learn from our competition, where we have working interests, and we collaborate to figure out how to do the best across the entire basin. That provides interesting learnings. We have our co-op program.
Our co-op program represents about 55%-60% of our overall production. Maybe if I summarize the two 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. 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. I wanna point to the basis of design because the vintage of these wells, where 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.
On the bottom right, you see this slide, the black line represents the aggregation of those three things across all of the wells. Around 70% of those wells were long-sitting DUCs. 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've reconfigured our well spacing. That, 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're drilling deeper benches 'cause we're targeting returns, which is why we reprioritized. Slightly deeper benches. You'll see more rig moves per section. 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. 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 basin. I feel confident in the outlook that Mike mentioned.
A somewhat unique set of circumstances that came together there and those learnings applied going forward. Do you have a follow-up?
Yes. I don't need you... thank you for prompting me. If I can look at slide eight, your mix of low decline offshore assets changes dramatically by 2027, which is your forecast. From your seat, how do you maintain the treadmill at that point? You know, you have a lot of shale assets contributing to your overall production slate at that time. They're high decline. I just wanna understand, how do you think the production profile will look like? You have 3% CAGR till 2027. What does it look like in 2028, 2029? I'm not asking for guidance, but just shape.
Sure. 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, left-hand side of this slide, what we've got are what we would kinda classify as our base production assets. It pulls the growth assets out and shows them on the right-hand side. You can see very shallow decline in that part of the portfolio, largely because these are facility limited, not field limited. You can think LNG plants.
You can think Kazakhstan, where we've got big surface facilities, and we've got some level of drilling that's required to keep those facilities full, but we've got big resource positions that underlie those. You know, on the right-hand side, you can see the Permian is gonna grow a lot. The Permian growth doesn't end in 2027. You know, 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, you know Nigel mentioned, Mad Dog 2 starts up this year, Anchor and Whale next year, Ballymore in 2025. We see more in the Gulf of Mexico, and then other shale and tight is a significant part of the portfolio. 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 a rapid decline curve. but that's becomes a long asymptotic tail, and you start to stack up dozens, scores, and hundreds, and eventually thousands of those long tails, and that's becomes a relatively shallow decline, large tranche of production. It doesn't take a lot of drilling on top of that to flatten out that, you know, that set of long, tails of production.
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 allow that to spin off even more free cash flow. We are not falling off the edge of a cliff anytime soon. Let me just finish it with that. I wanna get to some other-.
Can I maybe add a comment, Mike?
Yeah, quick one, and then we're gonna get to.
I think if you go beyond 2027, you look at some of the acreage position in the Eastern Med, we've got six 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. How do you tie back to existing infrastructure? 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 phases. We're just coming out of appraisal phases, you see a lot of that ramping up.
I think we've got a strong, diverse complementary asset base for the next five 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 we're gonna go Biraj, and I'm gonna go to the back. I see Jeanine with her hand up.
Thanks. thanks, Mike. Good morning. Doug Leggate with Bank of America. Can I take two? Is that okay?
Yeah.
Two questions. My first one is on the cadence of the free cash flow growth. I mentioned this to Nigel earlier. You mentioned the $5 billion of free cash from Tengiz in 2025. What is it currently? How does the cadence play out over that five year period through 2027? That's my first one.
I think if you look at the
Sure.
The free cash flow growth is growing approximately $4 billion in TCO, $3 billion in the Permian. 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. Then you've got pet chem growth in the towards the 2026, 2027 timeframe. I know you may ask about pet chem margins today, but that's not how we invest, right? If you think about the long-term fundamentals of chemicals. All of those are adding to that free cash flow.
Thanks for that, especially on the TCO and the Permian. That's really helpful. My follow-up is on slide eight. 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. If I check back, the last time oil was around $60, first quarter of 2021, you did about a $9 margin, it looks like. I guess my question is, what are you assuming for gas in the U.S. in that margin expansion? Obviously the mix is skewing, you know, towards gas domestically.
Yeah. I'm not gonna answer the gas.
Doug, we've not really changed our long-term price assumptions for oil, for gas, for NGLs, for refining margins. We're in a period of time where we've seen strength in a lot of these different commodities. Fundamentally, we believe that, you know, we're gonna revert to mid-cycle margins over time. You do see a little bit of a mix change in the, you know, the Permian over time, but the margin expansion is really driven by lower cost per barrel. OpEx per barrel down 10% over that period of time. DD&A, you know, we're much more capital efficient. You were around when we were spending $40 billion a year 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. You were adding higher margin barrels into the portfolio, and that net cash margin really just expands as a function of both of those. I would encourage you not to look at the mix effect and worry too much about gas pricing. It's really about cost efficiencies and scale, and as we start to see some of these volumes really come on.
Yeah.
Okay. Biraj and then, Jeanine.
Sure. It's Biraj Borkhataria, RBC. Thanks for the presentation and taking my questions. Also had two. The first one was on the base slide you showed again, the 1.5 million barrels a day. You, you name-checked Nigeria and some of the work you're doing there in terms of extending the base. Could you just talk about, you know, operating in that environment? Cause a number of your peers have sort of intimated that it's not workable given the security challenges and some of the things going on there. That forms a reasonable chunk of that base number there.
It's a reasonable chunk. It's not the largest chunk by any means. 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 deep water 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. Our portfolio over time has kind of increased our offshore position and we've, you know, got an important but not an enormous position in the onshore as well. Look, we operate in a lot of difficult places. You know, 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'd, you know, been looking to recover. 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.
Thanks for the, thanks for the color. The second one was on TCO. 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. Is there anything, any color you can give on, you know, how much of the contingency have you eaten through, and how confident are you that you know, that will be maintained?
Yeah. Nigel was there recently. Why don't you take that?
Yeah. I visited several times in the last few years. I was there in January most recently. You know, the way I'd answer that is that a lot of the risk in this project's behind us. If you think about mobilizing people, mobilizing equipment, this no longer looks like a construction site. Construction's complete. We're now in the active phases of system completion and commissioning and startup. Right now we're getting focused on the high pressure to low pressure conversion of the field. That's what improves well deliverability. That's where a lot of the work and focus is today, is commissioning utility systems that will allow that to happen later this year.
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 midyear and then begin to ramp up. It's complex. The startup is a lot of activity, a lot of work to do, and we've still got about 20,000 people there working, 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. You know, 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.
Now we're focused on is a safe and reliable startup of those assets.
Okay, can we get a microphone to Jeanine back here on the aisle?
Hi, good morning, Mike , Nigel. Thanks for all the time and detail today. We appreciate it. Two questions, if we may. The first one's on the Permian, the second one is on Eastern Med. On the Permian, love all the information with the type curves and, you know, kind of giving us an understanding of what was going on in 2022. Can you maybe provide a little bit of commentary on the cost side of things? I know you reiterated the production targets. I think prior thinking was it'd be about $4 billion a year or so that you would spend in the Permian. 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?
Want me to take that?
Sure.
I'll start with saying we are seeing some inflation pressures in the Permian. We see inflation around the low teens. A point I'll make is we absorbed a lot of that last year. We hit a development cost of less than $8 per barrel, despite some inflation head pressures last year. We're continuing to develop and improve and constantly looking for different ways to do that. I've been there twice in the last four months. I saw some great examples of innovation and improvement. Our guidance is just gonna be over $4 billion through the period. We do continue to see some of that pressures 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. you know, 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. 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 contracting for services in real time. we're also seeing technology and performance improvements to the, you know, 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-$5 billion range, which is actually the guidance a couple of years ago. Last year, I think we said $4 billion. Year before that, we'd said $4 billion-$5 billion. It's still in that $4 billion-$5 billion range.
Okay, great. You know we love our modeling, thank you for that. 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. Are we supposed to interpret that slide as there's not really much growth opportunity there? We know you've got Angola, you've 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, you've got great resource there. Just wondering kind of what the growth opportunities, if any, are available in West Africa. Thank you.
Yes. it is 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. That's where you saw some of the. 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 it be oil or gas. 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.
Thank you.
Okay. Over here to Jason, and then I'll come to Roger.
Hey, Jason Gabelman from Cowen. I'm unfortunately gonna ask another Permian question. You know, you're suggesting higher CapEx production, kinda stable and broadly, Chevron espouses this value over volume mantra. How do you tie those two? 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, 'cause it seems like, at least in the Permian Basin, there is a bit of, well, we wanna hit this volume target, but we're gonna increase CapEx to do so. I have a follow-up. Thanks.
Yeah. I wouldn't. Look, the CapEx guidance, as I said, Jason, is what it was two years ago, which was $4 billion-$5 billion to get there. It's within the range of, you know, a little bit of inflation coming into the thing, but we're not talking about a big program change. If you look at the ramp on rigs, you look at the ramp on completions, you look at the ramp on pots, it's consistent with what we've been doing. You've got a little bit of inflation that's gonna chew into returns. It's still the highest return capital dollar that we can, we can put to work. If it wasn't, then you would see, you'd 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. 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? If so, is that something you would be willing to look at expanding a trading business moving forward? Thanks.
Yeah. I wanna 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. It does not in any way, shape, or form constrain our investment opportunities.
Thanks.
Okay. Roger.
Sorry. Ryan Todd. A question first on the buyback. You increased the buyback guidance a little bit in terms of the range over the five 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 de-risked or you could kinda conservatively have confidence in the sustainability over the period. 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?
Yeah. Let me just frame the buyback within our four financial priorities, which have been longstanding. Number one is to increase the dividend. 36 years in a row, we've done that. Over the last five 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 five 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. You can think of that as $13 billion of cash on the balance sheet that doesn't necessarily need to be there. Then, with that low net debt, we got $30 billion of debt capacity before we start to tickle the bottom end of our guidance range on where we would see ourselves through the cycle. We've got capacity is the key point here.
You'll see when Pierre comes in here, I'll defer to make sure we get to a lot of questions here, more on this, we stress tested in a low price case, we tested in a higher price case, and what you see is that even if we're in a $50 world for 2025, 2026, 2027, we can sustain a $10 billion buyback. If we're in a higher priced world, which he'll show you is a $70 case for those years, which may or may not feel high today, you know, we can be at the high end of the range or even have capacity to do more than that.
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 where we wanna be countercyclical. We certainly don't wanna be procyclical. We wanna 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 $2 than the volume weighted average through the entire 19-year period, including we bought shares back in 2020, we bought shares back in 2021. 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 the range we've indicated.
Thanks. Maybe one follow-up question on Eastern Med. It's an area in asset that I think is 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. Can you talk a little bit about the Tamar expansion, you know, what's happening with the Tamar expansion, maybe the timing on that? 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 expand at Leviathan or incorporate Aphrodite or the material growth opportunity there?
Any comments around how that fits?
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 Leviathan.
Well, 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's producing at 1.2 BCF a day. We've got a great resource position, six exploration blocks in Egypt. We've got the appraisal well in Aphrodite.
We found a discovery in August 1 well. 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 as potential other avenues to access European markets. It's a fairly benign ocean, you know, in terms of floating LNG, it works. 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 then the future development. I think this really could be a. It is a really nice asset today, and it has opportunity for growth potential.
Brian.
Maybe to your question earlier.
Tamar likely to come online, the Tamar expansion early in the second half of this decade. Leviathan, as Nigel said, we got a couple options we're still looking at. That production is likely towards the latter part of the decade. Paul, and then the other Paul.
Thanks, 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 transport through Kazakhstan? I know there's kind of threats everywhere, but is there a, would that be the number one thing that you're worried about? 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. Is that the biggest risk that you face politically? I'm thinking, you know, Australia, there's risk. East 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?
Yeah. 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. As you say, there's risks right here in this country that we face. Last year, specific to that pipeline, last year, you know, there were some interruptions. It had 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. So look, it's a risk like many other risks that you cited, but it's one that's been managed very well. The Republic of Kazakhstan has been very engaged because obviously very important to the country. 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. It's important to world markets right now at a time when that production is needed. You know, we've been on top of it. The impact has been almost de minimis to this point, and we continue working hard every day.
Thanks. Is there any update on Neutral Zone? Thanks.
Yeah, 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. We'll be doing some pilots over the next year or two to look at some horizontal drilling, some other types of enhanced recovery technologies that may be appropriate. We'll talk to you more as we start to develop plans for further growth investments there. Paul Cheng.
Thank you, Mike. Paul Cheng, Scotiabank. Two questions a piece. First, want to go back into LNG. I think historically, Shell point and all the super major take an integrated approach and say you own the asset, you own all the transportation facility. Recently you sign a supply contract in the Gulf Coast. Seems like it's break away from that. My question is that in the, by the second half of the year, of the decade when you start to expand your footprint, again, in the LNG, is the strategy going to be a more focused on the asset light or that you're still going to use the traditional model that you want to fully integrate?
Also whether that you are concerned because it does seem like there's a lot of LNG project coming on stream after 2025. I think a rough count is probably 80 million, 90 million ton per year kind of capacity. Is that a concern?
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 needed 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. 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. 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.
Yeah. How about with, seems like a lot of capacity coming on stream. Is that a concern?
You know, it's like so many parts of this industry, Paul. You get surges of capacity, and markets tend to get oversupplied, and then Work that capacity off. So LNG has been, you know, like that, petrochemicals refining. 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. Demand for LNG is growing. Demand for gas as the world is growing. 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 talk about the onshore. Can you talk about the offshore, 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 will that impact on your development pace there?
Well, I highlight the inflation rates primarily in the Permian, and Mike made some good comments around how they're indexed. 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 are all contracted up, so we don't see any real change to that, but mainly in the low single digits internationally.
Low to mid, probably.
Yeah.
Okay.
It's fine.
All right. Yeah.
Thanks. Alastair Syme, Citi. I just wonder if you could give us a quick map of the other shale and type piece. Just one question. This is the overview of how those different businesses stack up.
Go ahead.
There's a slide in the appendix, actually, which shows, if you could pull that up. Thank you. If you look at our shale and tight assets, it was pointed on the far right side of our growth pictures around 200,000 barrels a day of growth, primarily driven by the three assets we have in Argentina. El Trapial is in development. The other two are just wrapping up appraisal. DJ Basin is the other primary growth. We've got rig lines being added there and activities. We're gonna add almost 70% more POPs in 2023 than we did in 2022. Still a flexible base. Haynesville, we're just adding one rig line. Part of our I talked about that a little bit earlier around part of our natural gas position.
The other reason we're doing this, 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. 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?
No, no. Can you talk a little about the economics of Argentina?
Yeah. 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. 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 we're encouraging or that we see risk growing, we can either accelerate or slow down our activity. We're gonna take a very measured but deliberate approach to how do we develop the Argentine resource.
Okay, I'm gonna try to squeeze in a couple more quick ones here. John, then, yeah. I mean, I try to not allow people to double up just to spread it around everybody.
Hi, good morning. John Royall from JPMorgan. On the $15 billion-$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? Longer term, what do you think of as an optimal mix of growth versus sustaining, once you're, you know, no mega projects post Tengiz?
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. Two petrochemical projects that we've sanctioned. I just talked about some of the shale activity. We got a project at our Pasadena refinery. There's a lot of puts and takes, John. As we look at managing this for ratability and for execution, 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. 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. There's constantly projects that are reaching their peak spend, that are coming off their peak spend. And we trade those off as we stay within the, you know, within the guidance.
Great. Thanks, Mike. I don't think you've gotten a question on Venezuela yet. How are things progressing there? How long do you think it'll take to scale that up? What's a reasonable expectation for Chevron's production in Venezuela?
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 beginning to 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 empresas mixtas. We're seeing production respond. I mentioned at the fourth quarter call that production's 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. We're seeing some early progress, still focused on safety and asset integrity. We'll go slow there.
You know, the shift in policy by the U.S. government is relatively recent still. We've got questions about elections coming up and other things. I would expect us to go slow and we'll update you as we move along. I wouldn't figure that as a real growth-y 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.
Thanks. Phillip Jungwirth with BMO. Two 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. Just thinking about it in terms of a lot of the major projects are booked, and then you're somewhat limited under the five year rule in terms of shale and tight and Permian bookings.
Maybe we can pull up. We got an appendix slide on reserves and resource, and I don't wanna spend too much time on it. You know, over 10 years, we've been at 99%. If you were to look at a one, three, five year period, they're, you know, a 97%, a 102%. 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 barrels today. 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 the Gulf of Mexico shelf. We had some North Sea.
We had, you know, we had gas in the far northern reaches of Canada for Kitimat. A lot of the stuff that's gone out of the portfolio was unlikely to compete for capital. It's been replaced with much better return, more likely to be developed or resourced. So it's sitting there with, you know, 78 billion barrels of 6P resource, to keep feeding reserves over time. We do have some things with the five year rule that will govern how fast some of that comes into proved reserves. But we don't have concerns about reserve replacement.
Thanks. My follow-up question would be on that 6P resource slide and as it relates to the Permian. 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 reserve resource or more importantly, the PV10 of that resource.
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 a third 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. 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, this is royalty advantage.
It's 27 billion barrels, most of which has low or no royalty because it's fee property. The Permian is it is a resource I wouldn't trade for anything in anybody else's portfolio in the industry. Okay. I was gonna get to Lucas, and then Neil. We're just running a touch over time, so I'm gonna try to be quick.
Right. Mike, one question, and in ways it goes back to Paul's question, and it's really around, you know, monetizing gas and LNG strategy. Firstly, remind me of your position in Venezuelan gas. And I ask simply because of, you know, the efforts at the present time to keep Trinidad and Tobago filled. Paul, not your asset, obviously. But I guess secondly, as I start thinking about, you know, your portfolio and Ullage disappearing in other facilities, you know, Egypt, Equatorial Guinea, Northwest Shelf, Indonesia, West Nile Delta . I mean, you have resource located around almost every one of those facilities, and I would guess an opportunity to monetize.
To Nigel, I mean, the question is, does go back to Paul's, it's to what extent, you know, that starts to become front and center of minds in terms of monetizing gas in a very, should we say, financially beneficial way?
We do have some resource offshore, some gas resource offshore Venezuela. It's tricky as things are in Venezuela. The broader point that you're making, Lucas, is I think one that you're gonna 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, you know, 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 a Gulf of Mexico brownfield tiebacks, right? 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 time and lower risk. I think you'll hear us talking a lot more about that in the years to come. Okay. We're gonna go to Neil, and then, and then I gotta take a break or, your next speakers are gonna 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. 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? Thank you.
You wanna talk the why first or-?
No, go ahead.
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. It's really about bringing consistent and disciplined execution, whether it be to how we think about using existing infrastructure to monetize resources, to Lucas' 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. You start to think about running those as a business proposal, you know, together. How do you leverage best practices? The same in our complex facilities in upstream. What we're seeing is there's things that are common across upstream, downstream and midstream. Turnaround excellence is an opportunity for us. What we're trying to do is bring out the best in what we do today and accelerate progress. With all those organizations being under one, it's a little bit simpler to actually do that. 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 gonna restart on schedule. Coming in next will be Jeff Gustavson and Eimear Bonner to talk about New Energies. Eimear will talk about technology, including ask her about the Permian. For those of you that got all these Permian questions, Eimear's doing a lot of interesting work in the Permian Basin. Thanks for joining us today. 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.
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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 oil seed 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 U.S. 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 offshore 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 three separate permits to study storing CO₂ in areas off Australia's northwest coast 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 cost of capture, using our own assets to pilot new technologies. 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 de-risk 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 co-developing 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 solution 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 three 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. 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. 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.
I think Sam had his hand up first, right over here.
Hello. Sam Margolin, Wolfe Research. My question's on carbon capture. I think under the Paris Agreement in the UN, something like 15% of GHG emissions can be addressed by carbon capture. That's essentially like 100% of Scope 1 and 2 across the industry. What we're also seeing is a lot of greenfield projects because carbon capture incentives are very robust, and people are almost creating emissions just to capture them. The question is, you know, how big do you think your carbon capture business can get? How much of your, you know, initial Scope 1 and 2 emissions can you address? Then, you know, is this one of the markets within low carbon with one of the largest growing TAMs that you see, given the policies? Thank you.
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?
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, carbon capture is a part of any net zero pathway. 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. 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 including our own. That gives you a sense of the size.
Last or a year and a half 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. That's a marker that's out there. We're making good progress towards that target, 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, petchem, cement, steel emissions, all in that area. 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 and how they can participate in that regional hub development. That's just one hub. 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 Bayou Bend in the U.S. Gulf Coast. We're also looking at how we can deploy these technologies to abate our own emissions. 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. There will be more opportunities as we go forward. Eimear, you might talk about the technology a little bit in San Joaquin Valley.
To support all of those ambitions, both in our business today, 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 cost. Understanding then when we do capture CO2, how to store it safely and efficiently in reservoirs. Really two main themes, lowering capture cost and storage. Jeff referenced some of the pilots that we've got ongoing. We're studying a few different capture technologies to understand which one might work best with our facilities. We've got one running in San Joaquin today. 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. Then we're also going to test concentrator technology, so how to integrate some of those together. 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. 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 allow us to not only look at where's 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.
Those are the two technology themes 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.
That's a great combination, the two of those things, the internal customer base, scaling technologies, but the external size of the market. You asked about which of these businesses 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. 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.
Thank you, guys. good morning. Paul Cheng, Scotiabank. two question, please. First, can you talk about how you guys view internally on the financial matrix when you make decision on project? How that different than your traditional oil and gas or refining projects? I mean, clearly, you talk, different nature of the project that they would be different. Trying to give us a framework, how should we look at that from a company standpoint? The second question is that on LNG, I think the company does have operation over there in that one of your European cousin, actually two 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 internal opportunities or organic opportunities are sufficient for the pace? Thank you.
Thanks for the question, Paul. On metrics, the metrics are the same. We use the same metric, metrics to measure the economics for these investments that we use for any investments we make across the company. 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. At the end of the day, for these businesses to be sustainable, we have to generate returns. We wanna generate higher 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.
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, the same metrics apply. As we go forward, hopefully, we'll be able to work on the technology, lower the costs, sign up our customers, have more clarity on the policy incentives that, you know, marry with these businesses, and we'll be able to narrow those bands of uncertainty. We use the same metrics. I think your second question was around M&A. If-
On how it, specifically for RNG.
For RNG.
Right.
Yes, for RNG. Well, clearly, you know, 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. In the renewable fuel space and the new energy space, the best example of where we've used M&A was the REG acquisition last year.
Very happy with that as-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 put out in 2025, $500 million-$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 two companies, you know, bring together. 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.
Then we'll move to this side of the room.
Thanks. Jason Gabelman from Cowen. A couple years ago, I think you put out targets around the lower energies business of $1 billion of cash flow from $10 billion of investments over, I think it was eight years. Can you discuss, have either of those numbers changed at all? Has the makeup within those numbers changed at all? Thanks.
Yeah. 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'd 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 longer queues now than we can invest in, but not all of those opportunities are investable opportunities. 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. 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. A hydrogen business. We're doing a lot of study in the hydrogen space to drive even greater cash flows, I think, next decade.
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.
So, uh-
We have one follow-up.
On lowering, maybe I'll just talk about-
I'm sorry.
lowering the carbon intensity of our existing assets. Jeff mentioned the marginal abatement cost curve. This is the approach that we use. We look at all the opportunities as a portfolio, and our goal is to abate the maximum amount of carbon for every dollar that we spend. We have a large portfolio of projects, over 100 projects. We've got great momentum building around execution. Last year, we actually grew the portfolio a lot. We executed 13 projects. We'll execute three to four times the number of projects this year. 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 mentioned the one in Nigeria, where on a gas turbine, we upgraded the air filters. The upgrades were to mitigate fouling 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. We see example of examples. That's an example of one of the projects within that marginal abatement cost curve portfolio, and that's focused on lowering the carbon intensity of our existing business today.
Thank you.
Great. Thanks. 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. If you 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. Thanks.
Yeah. We've said in the past, policy support is important here. We're focused on areas where we have, you know, capabilities, where we have assets, where we have existing customers, in policy-enabled markets. That's a key part to the, especially the early stages of growing these businesses. 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, 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. Not just broad tax incentive or other support, you know, 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, CCS, 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. 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 cost to make them more viable, for longer with less policy support. IRA, one step, but just one overall step. Hasn't changed our broader plans or strategies.
Thank you. We'll go right up front with Doug.
Thanks, Jeff. Doug Leggate from Bank of America. Two 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? 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 five year, I believe it's five-year lows for LCFS prices. Certainly, that is an incentive that is important for the renewable fuels business. 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. You know, our longer term, we make longer term projections just like we do on our commodities, on the commodities that we sell, oil and gas. We don't release those, you know, externally, but that's something we look at. We do see LCFS prices strengthening in the years to come, as, you know, carbon regulations continue to tighten.
It's just one component, policy is just one component. What's really important in running our renewable fuels business is, you know, 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. I mentioned the Geismar expansion, which is on track and on budget. It's accessing the right sales and distribution channels, and this is where REG and Chevron really complement one another, and 1+ 1 equals much more than 2. That's very important with these policies change.
LCFS we think will spread to other geographies over time or similar type 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, you know, 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.
Yeah. We're focused on enabling feedstock flexibility, while lowering costs and maximizing yields. 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 we've got experience with today. We do a lot of feedstock testing in the lab. We assess feedstock, we test them, we qualify them. 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 hydroprocessing, the pretreatment, we've got a lot of technology efforts there as well. What we're trying to do physically is kind of design catalysts that will work at different operating conditions.
Whatever gets thrown at them, they can manage, and they can manage higher temperatures and still secure the yields required. That flexibility, and we're using our expertise in catalysis and hydroprocessing and in metallurgy to really develop a solution set there. We have to care about the cat itself because of the different reactions also that go on. At the other end of the value chain on the product side, our JV efforts with Cummins and some of the OEMs, we're testing these new products. We are everywhere on the value chain when it comes to technology. What's been great with the 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 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 co-processing today in El Segundo, and we've got conversions planned this year as well. 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 there, and we'll keep moving to this side of the room, I promise.
Hey, Neil Mehta here with, Goldman Sachs. Thanks for doing this. 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? 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? Thank you.
Yeah, thanks, Neil. On capital, we mentioned the guidance, the $10 billion over eight years. No change to that guidance. 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. 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. We'll continue to provide updated guidance as we go along. In terms of, you know, percentage of the overall enterprise, you know, I'd let maybe Mike or Pierre speak to that. We go out and we've launched these business. 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. We're in the earliest days. We'll see where this progresses as we go forward year- to- year. On competitors, I, you know, I'm not gonna speak to any another competitor's strategy. 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 in 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 standalone 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.
We're investing in that in a different way than some of our peers. 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, 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. We're, you know, 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.
Hi there. It's Biraj Borkhataria, RBC. I have two questions. The first one is on hydrogen. Can you just talk to me about the economics on this space? 'Cause 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. From your side, you're talking about shipping ammonia from Gulf Coast and West Coast to Asia and Europe. To be frank, every time I run the numbers on something like this, it's not even close to making economic sense. Can you help me understand-
How that can be competitive relative to other sources. The second question is on CCS and particularly for LNG. Kind of two-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'm just interested to know. Thank you.
Okay. Yeah, we'll hit both of those. There's a big technological angle on hydrogen, particularly transportation storage, which is the highest cost part of the value chain. Eimear can speak to that. We'll get into the latest on Gorgon as well. Look, I mean, in order to generate at-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, you know, bearing that higher cost today faster. We're working with many of those companies in the world. I mentioned JERA in my opening remarks.
You know, here's 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. Those are. They've high ambitions. They're challenging. It's, you know, 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. 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. You know 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. We feel with the investment in technology, lowering the cost of delivering that hydrogen, with still the appropriate amount of policy support to start, we'll build this new energy 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 CCUS.
From a technology perspective in hydrogen, we're focused on two things. One, lowering the cost of hydrogen production, and two, lowering the cost of hydrogen transportation. As Jeff talked about, there's carrying hydrogen and ammonia, other fluids that carry hydrogen. That's some of the technologies that really talk to the transportation challenge there. The way we look at this is we have tech ventures, and we make investments in companies and learn from them. This is an area where we've made a lot of investments, three investments over the last two 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. Think about this liquid as carrying hydrogen to its destination.
You gotta put the hydrogen into the liquid, at the customer end, you gotta take the hydrogen out. We're not only studying how to put the hydrogen into the fluid, 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. That's why we're really interested in that. JERA, who's a great partner of ours, we're doing a pilot with JERA to test this actually in L.A., in California, just to see whether we can make it viable.
That's just one example in the transportation sector that we think offers promise to kind of unlock the constraint right now.
Great example. On Gorgon CCUS, First of all, Gorgon CCUS, one of the largest, most complex CCUS projects in the world, started up three years ago. 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 through some of the unique aspects of that or the technical aspects to give a little more color on the, on the question.
Thanks, Jeff. On Gorgon, when it comes to capturing the carbon and injecting the carbon into the reservoir. That's working. 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. The reservoir that the CO₂ goes into, we have to take water out to create the space for that CO₂. We've had constraints on the water side. The water that we're taking out of the reservoir has sand, it has particulates. It has to be processed, and we're constrained right now as to how much we can do. The solution is to improve the surface equipment to handle the solids and the particulates and actually to pull more water out.
Once we can pull more water out, we can put more CO2 in. The CO2 is really working. The constraint is on the water management side. What we have done with Gorgon is we have 4D seismic. We have fiber optic 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. 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.
Hi, Nitin Kumar from Mizuho. I have two questions. One, Eimear, you mentioned a technology for improved recovery in shale. I hate to bring oil and gas into a low carbon discussion, kind of curious, just, one, is it primary? 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? 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.
I'm just trying to understand what does $8 billion get you from where you are today to those targets?
Thank you for the question. You wanna take the-
Yeah, I'll start with the shale and tight. Thank you for asking the question, because technology is critical for our existing business today to safely deliver higher returns and lower carbon. With shale and tight, maybe I'll just maybe connect the previous discussion. I think some of the things that we've learned in Permian around how fractures behave, how benches interact, how much communication there can be, a lot of that was actually discovered and informed by technology. Tracer technology, tracers that we put into the frack 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.
That surveillance program, which is constant and will be adjusted as we adjust our frack designs and our well plans going forward. That's just something that's part and parcel of normal business and learning how the reservoir behaves. The recovery project is something different. This is secondary recovery. This is using leveraging our expertise in advanced oil recovery to change the dynamics in the reservoir, right? To change how the water and oil moves in the reservoir and how the oil interacts with the rock, and adjusting that chemistry so that we can recover more oil. That's what I refer to in my remarks. We're doing that a number of ways.
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. We've done 100 pilots across the shale and tight asset classes. 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. 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. That's what we're studying. We're studying it in the lab, and we're studying with our partners as well.
Thanks, Eimear. It's fine to ask a lower carbon or an oil and gas question in a lower carbon session because one of our lower carbon strategy is to lower the carbon intensity of our existing assets in the Permian. It's obviously getting a lot of attention, not just for that, but for other reasons as well. On your second question, the capital guidance was consistent with the target. 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 biodiesel, bio-based diesel at the end of the decade. We're the second-largest producer in the U.S.
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. 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 JERA. 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 gonna 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 one more question? Last question, please. Thought there was one here.
Hi, good morning. John Royall from JPMorgan. Can you just talk about the opportunity set in sustainable aviation fuel? We've seen a couple FIDs in that area, and I think the changes from the IRA make that business kind of more attractive. Where does SAF sit within your opportunity set? I think, you know, more broadly, and then maybe just on the renewables side.
Yeah, gets a lot of attention in the company, a big focus area. You know, we're focused on hard-to-abate sectors. Transportation is a critical, you know, group of those sectors. We're also looking at power and industrial customers. I've given a couple of examples of that. 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. Aviation is certainly the big kinda 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, you know, with us and others about how we can help them lower their carbon intensity.
SAF, sustainable aviation fuels, is a big part of that. 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, you know, nominal capital investments we could make to significantly grow the SAF capacity out of that asset? Policy support is important, but even more important is getting to the right commercial agreements with the customers, in this case, the aviation industry.
We think we'll get there, but it'll take time for that to develop. Thank you for the question. That is the last one. 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.
Thank you.
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Hi, I'm Monica. I'm an engineer here at Chevron. My passion is working with young girls and getting them interested in STEM. It never dawned on me that being an engineer was not something that a woman was seen as doing. I mentor a lot of girls and I have a daughter of my own, I need to have that integrity to stay honest to them and to myself. Integrity is one of our Chevron Way values. I think it very much is integrated into the culture.
To make progress, we must keep taking steps forward. We believe the future of energy is lower carbon, and to get there, the world needs to reduce global emissions. At Chevron, we're taking action, tying our executives' pay to lowering the carbon emissions intensity of our operations. It's tempting to see how far we've come, but it's only human to know how far we have to go.
My name is Ashwin, and I work as a competitive intelligence lead. My passion is volunteering at my daughter's school. My daughter's small class has the representation from, like, more than seven, eight countries. The exchange of ideas and learnings that goes on in that small group without any kind of bias, it always helps me relate it back to the focus we have in Chevron on diversity and inclusion. It makes me a better team member. It helps me listen to them more carefully, understand where they're coming from, and then make the most out of the teamwork.
Why would an oil and gas company look to power a truck with plant-based oil? We believe power is all around us, and it's only human to harness it for good.
My name is Ulises. I'm a project manager. My passion it revolves around cooking. There's always new ways of creating food to have to be on the forefront of the new technologies. My job in Chevron also involves a lot of discovery because I'm always looking into what new technologies are coming up, CO2 or fuels or water management. We have to understand where things are evolving and how they're relating to each other and to us and to the future.
What do cows have to do with the future of trucking? At Chevron, we're working with partners to turn the methane from cow waste into the fuels of the future.
My name is Merche, and I'm a communications advisor. I particularly like to dance a type of dance called Rueda de Casino. It's a dance from Cuba. I think what makes this dance so much fun is that there are so many different types of people that do it. You have to learn how to collaborate. If everybody does their part and is really paying attention, then the dance is successful. You can find the same thing at work. There are so many of us, you need to be able to work and talk to other folks to get the benefit that all of us can bring to the table.
When I'm singing in the choir, and we are all, you know, singing harmoniously to a piece, you feel so connected. My name is Onyekachi, and my passion is singing. What I love the most about singing in the choir is that we're all working towards the same common goal. Likewise, when you're working in a team in the workplace and we achieve that result, the outcome is very harmonious and is very wonderful.
What's on the horizon? The answers lie beyond the roads we know. We recognize that energy demand is growing, and the world needs lower carbon solutions to keep up. At Chevron, we're working to find new ways forward through investments and partnerships and innovative solutions like renewable natural gas from cow waste, hydrogen-fueled transportation, and carbon capture. We may not know just what lies ahead, but it's only human to search for it.
Hi, I'm Monica. I'm an engineer here at Chevron. My passion is working with young girls and getting them interested in STEM. It never dawned on me that being an engineer was not something that a woman was seen as doing. Because I mentor a lot of girls and I have a daughter of my own, I need to have that integrity to stay honest to them and to myself. Integrity is one of our Chevron values. I think it very much is integrated into the culture.
To make progress, we must keep taking steps forward. We believe the future of energy is lower carbon, and to get there, the world needs to reduce global emissions. At Chevron, we're taking action, tying our executives' pay to lowering the carbon emissions intensity of our operations. It's tempting to see how far we've come, but it's only human to know how far we have to go.
My name is Ashwin, and I work as a competitive intelligence lead. My passion is volunteering at my daughter's school. My daughter's small class has representation from like more than seven, eight countries. The exchange of ideas and learnings that goes on in that small group without any kind of bias, it always helps me relate it back to the focus we have in Chevron on diversity and inclusion. It makes me a better team member. It helps me listen to them more carefully, understand where they're coming from, and then make the most out of the teamwork.
Why would an oil and gas company look to power a truck with plant-based oil? We believe power is all around us, and it's only human to harness it for good.
My name is Ulises. I'm a project manager. My passion it revolves around cooking. There's always new ways of creating food to have to be on the forefront of the new technologies. My job in Chevron also involves a lot of discovery because I'm always looking into what new technologies are coming up, CO2 or fuels or water management. We have to understand where things are evolving and how they're relating to each other and to us and to the future.
What do cows have to do with the future of trucking? At Chevron, we're working with partners to turn the methane from cow waste into the fuels of the future.
My name is Merche and I'm...
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 cap employed. Over time, we expect to be a solid double-digit ROACE company at mid-cycle prices. With our higher oil price exposure, Chevron is doing much better than that, delivering ROACE greater than 20% last year and leading the peer group in ROACE improvement over the past five years. Capital efficient investments, combined with strong production growth, drive higher cash flows. 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-$20 billion per year.
The higher range is supported by two cases shown here and reflects our greater capital efficiency and low dividend break even. 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 stays flat, Chevron is positioned to repurchase shares annually near the $10 billion end of the range. 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 two 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 two 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 rank 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.
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 three 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. 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 start with Jeanine.
Hi, Mark, Pierre. Thanks so much for the time today and all the details. Nice to see you in person. We've got two 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 run 50 through the whole case, particularly on the cash, the debt side of things? Our second question is really on the break even. Can you just quantify, if possible, how that trends through the forecast period through 2027? Thank you.
Thanks, Jeanine. 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 five years twice, more than two times our nearest peer. The second is to invest to grow both traditional and new energies. Our CapEx is up 30%. We kept our CapEx guidance unchanged. The third is to maintain a strong balance sheet, the fourth is to return cash to shareholders in the form of a steady buyback across the cycle. We increased our buyback range to $10 billion-$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. What's gonna happen over the next five years?
None of us know. We run different scenarios. You can assume our mid-cycle is in between, around $60 Brent. That's flat. That's nominal. We have an upside case that ends up at $70, and a downside case that ends up at $50. The sources of cash first starts with our balance sheet. 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 wanna 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%-25% through the cycle.
We're at 3%, that's a lot of excess debt capacity. We have a $50 breakeven notionally to cover our dividend and our CapEx. The Brent, the oil 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. We're using the breakeven as sort of a mid-cycle on the other factors. We're gonna generate free cash flow growth of more than 10% a year from Permian, Tengiz, Gulf of Mexico, other assets, petrochemical. As free cash flow growth increases, our breakeven declines. We're gonna grow our dividend, and that goes the other direction. Yeah, over time, our breakeven will go down. You know, we could run a lower case, and we have.
We were the only company that showed a two year stress test at $30 Brent in the depths of COVID. 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 surplus cash and the excess debt capacity. I wanna 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 work 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.
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. If you went to $40, I think you know our sensitivities, it's $4 billion for each $10 change in Brent. We're happy to run lots of other cases. We think that's a very reasonable case. The only change from the prior year is we had 5 at $50, and when you're sitting at $80 or $100, it just seems like the first year or two just wasn't realistic, so we try to give more realistic cases. Let's go to the back.
Thank you. One of the, I think the hallmarks of the last couple of years for Chevron has been the focus on ROCE. A couple questions as it relates to that. You know, your confidence interval in terms of getting to the 12%, and then, as you think about M&A, one of the challenges, even as we were talking about Anadarko, it was M&A has a tendency to be ROCE dilutive because you mark-to-market the asset immediately at the point of M&A. Just how does that factor into your decision-making as it relates to those investments? Thank you.
I'll take the front end of that, then Pierre can close out on it. You know, 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. The Gulf of Mexico. 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, we'll continue to take advantage of that today. The point I would reinforce is that we don't need it, 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. We'll look for sure at earnings accretion. We'll look at, you know, cash flow accretion or free cash flow accretion. ROCE accretion is a nice thing to do, 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.
There's got to be something in it for our shareholders, the durability, and we'll look at a variety of metrics. You're absolutely right, that's one of the toughest ones. We've shown we can do that too. Doug.
Thanks, gentlemen. Doug Leggate from Bank of America. Cash CapEx, Pierre, I wonder if, I know it's a favorite topic that you've periodically given us guidance on. 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? I've got a follow-up, please.
Our current budget on CapEx, and we changed our nomenclature to CapEx and affiliate CapEx. It conforms with most how others do it. The consolidated company CapEx is $14 billion. Our guidance is $13 billion-$15 billion. There's $1 billion of range to move up as our affiliate CapEx goes from $3 billion-$2 billion. We're still within the $17 billion combined number that we've been talking about. 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. We'll announce our annual CapEx budget, you know, 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 to still go in.
It could be absorbed by some inflation, but right now the plans are that it's primarily increased activity in Permian and other shale and tight.
Yeah, if I could add on that. The piece that I would reinforce is what that capital discipline on this portfolio has delivered over the last five 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 had a second follow-up?
Yeah. My follow-up, and it's kind of bit of a self-serving question, so I apologize. Mike also alluded to or mentioned the possibility of significant expansion in your LNG portfolio towards the end of the decade. I noticed you're using in your assumptions $4.50 average Henry Hub gas prices, which apart from 2022, I don't think we've seen that in quite a long time. When you think about the big picture, LNG growth, LNG expansion, $4.50 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. I think I'll address the context that Mike was creating first. You can tag on here, Pierre. Our gas portfolio is Pacific Basin leveraged and Pacific Basin focused. That's with our associated gas out of the U.S. and our strong position in Australia. We've begun to increase our exposure to Europe. The structure is to be Pacific Basin weighted and have growing exposure to Europe. We've taken actions. You know, clearly we've got our U.S. Gulf Coast offtakes that'll come towards the latter part of the decade. We have a strong West Africa position that we're keeping full and effective.
Of course, we have our Eastern Mediterranean piece, which I think is 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. If that decision, although likely made from a design standpoint this year, that wouldn't come to market until later in the year. 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.
Yeah, just to address that. I mean, it's a 2027 assumption, so we'll see. It's been a very warm winter and obviously, price oversupplied. You know, we've said with no structural change in oil, right? $60 our mid-cycle 2027 assumption. No structural change in refined products. We have said with the war in Ukraine, and the EU, you know, reducing Russian supplies, that those molecules aren't finding their way into the market. There's gonna be more LNG exports. We've positioned ourselves with offtake agreements, but that'll be a pull on Henry Hub prices. It's a modest increase from where we were prior year. It reflects what we think is gonna be likely in five years, a little tighter pull on Henry Hub, and really mostly for exports to European markets.
Yeah. Long term, we believe in Asia strength. Let's go to over here. Biraj.
Hi there. Thanks for taking my questions. Biraj Borkhataria, RBC. Two questions. The first one's 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. Could you just help me understand if there's any, you know, changes? I know affiliate CapEx has moved down, so that flat has the free cash flow. Just a bit of color around that would be helpful.
Secondly, on the dividend, if I'm thinking about, you know, 3% production CAGR with margin accretion, which is what you point to, plus buying back your 3%-6% of share capital each year, that kind of points me to a dividend growth rate over the medium-term, about 10% per annum. Obviously subject to price. Am I 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? It led you to what number?
10%.
10%. Let's see. On free cash flow versus cash from ops, I wouldn't read a lot to it. We've gone back and forth a little bit. It's how the numbers shake out. I think we're gonna stick with free cash flow. I think 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 decide to do it on absolute free cash flow, Obviously, the share count is decreasing significantly in these scenarios with the buybacks. Let me take the dividend-
Sure.
You can add Mark to either one of these. You got 3% production growth. You know, we talked about reducing OpEx per barrel 10% by 2026 at mid-cycle conditions. You've got margin expansions. You know, you've got the shift in how we're investing our capital, so we're much more efficient capital investment. All of that says that's where you get the 10% free cash flow growth. 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. When we think about dividend increases, we're thinking about an increase in perpetuity, right? We have to have confidence that we're gonna 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 buybacks is a way to return cash to shareholders over a cycle that's excess to the first three priorities. The dividend is returning cash forever. That's how we view it. They're just operating on different timelines. 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 five year dividend of growth, twice our nearest peer, we're doing that in addition to significant buybacks.
Thank you. Over here, Sam.
Hi, Sam Margolin, Wolfe Research. You know, inflation is a hot topic, and it is particularly important to your program because everything kind of fits together like a puzzle, right? Inflation can really be a grenade in that. The question is tying back to the margin expansion slide from the first panel and then the free cash flow growth targets. You know, 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. The question is, you know, is there any tension or friction? Is there an inflation point where some of the mix shift gets threatened, you know, where it changes? It's cheaper to stem decline in conventional than it is to start new projects.
The question is that, is there any inflation risk to the margin expansion targets on the basis of projects, you know, moving out of the stack?
Yeah. 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%-7% range for the entire portfolio, and then let's say low double digits for the Permian. 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, you know, 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 shale and tight resources are very competitive. Our ability to stay within our capital forecast while increasing activity is built into the current plan. It is something we'll have to watch. If inflation continues up, it's something that we can test over time.
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. I'm 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 we're working really hard to offset it. Yes, if we see sustained high inflation rates, which we're already seeing some things moderate at this point in time.
I'd also say, I don't think there's a structural change in the service company industry. It's near capacity, right? Rigs are near capacity, sand's near capacity, lots of things. 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. I think we have a lot of tools to manage inflation. If we saw sustained high inflation, then of course that at some point in time, we could revise our CapEx guidance.
Yeah. I don't know if you had a chance to ask Eimear this question, but the application of technology in the business continues to provide dividends. You know, 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 on a unit basis, we may be able to offset the pressures that we're experiencing.
Okay.
Hi, Nitin Kumar from Mizuho. I wanna pick up on that last point you just said. 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, from our standpoint, remember, with the return-based decisions, production for us is an outcome and always has been an outcome. 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 in return that we don't need to grow faster. We just need to continue to get the highest returns to the business. I think 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, you know, PMs, of value investors, increasingly some, you know, growth at a reasonable price. Our 3% growth, I mean, you can do the math. We're showing more than that. We wanna have high confidence in our ability to deliver on it. We're not going to, if we can deliver these business results with less capital, that's what we're gonna do. We're much more capital efficient than we were. 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 said and 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. It's this consistent quarter in, quarter out, showing capital discipline, working hard to have efficiency that offsets inflation, using technology to improve returns. If we can grow 3%, find margin expansion two other % 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, you know, 5% of the earnings of the S&P 500, sorry. Yeah, 5% of the S&P 500 by market cap, or more, or 10% by earnings and cash flow. We still have a lot of upside with investors. We gotta show it quarter in, quarter out, and grow at reasonable rates and do it with the least amount of capital. That's the mindset shift that you've seen.
There's a portfolio shift, there's really a mindset shift. Our engineers are how do we get this project done with less capital? 'Cause if not, they're not gonna get the capital. The bar is set really high. The Permian sets a high bar, other shale and tight. You know, even how we're doing Gulf of Mexico is very different. You know, we used to do sort of custom designs and sized it to maximize, you know, initial productions. Now they're sized in a standard way, a longer plateau. 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, we are.
Your fault, you're good.
Do I get a follow-up or-
You may have a follow-up.
Sorry, I don't wanna... I'm not gonna hold this-
It's all performance-based, but go ahead.
Sure. Mike said in an earlier question that 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 wanna be counter-cyclical, not pro-cyclical. Could you sum that up for us? What is your... I won't hold Mike's comment against you, but if you wanna talk about your macro view and then the decision to lean into the share buyback pace, starting the second quarter.
Well, let me start, then Mark can add. The buyback guidance is a sign of confidence in the company's ability to generate surplus cash to those first three priorities. It's because we're more capital efficient. It does reflect what looks like more of an upside case over the next several years. We have the range, and we intend to use it. Again, we're not trying to be counter-cyclical. We're trying to be across the cycle, and we're trying not to be pro-cyclical. I think most of the various cash returns to shareholders are pro-cyclical. Variable royalties, special dividends. It all works great in the upcycle. What do investors get in the down cycle? What investors get in the down cycle with Chevron is, of course, the dividend. That'll continue to grow, right?
It grew through COVID. You'll get that steady buyback even in those out years. We're setting it at a level that we can maintain it across a number of years. Commodity prices and margins are gonna bounce up and down, and we're just gonna set a level that we have confidence that we can maintain it for multiple years.
Yeah. I just wanna 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, it's 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, you know, just give us high confidence in that.
Just to put a point on it, that's all at $60, right? That free cash flow growth obviously at $70 is even higher.
Okay. Paul?
Thank you. Paul Cheng, Scotiabank. Two question, please. I have to apologize. I want to go back into the buyback. I think in your high and low case, we need the distinction is by 2025 and forward, whether you see $70+ or whether you see $50, right? 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's reopening. We don't know exactly what that's gonna how that's gonna show up. We have the central banks tightening interest rates. We had a strong PCE number on Friday running hotter than people expected, 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. There are a lot of factors that could drive it, and so we're just doing our best gauge of where we see, you know, the next several years going, and we're setting it 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 is in there and what we see on the supply side. It's all the factors that you normally track, but they're uncertain. The future is uncertain, we have a range of scenarios, and we have a range on the buyback. Again, we could have a much bigger buyback right now, but that would be pro-cyclical. We're setting 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.
Yeah. I would just reinforce the uncertainties. You know, if I had to pick the biggest uncertainties today, we were talking about this earlier this morning, some of us, the idea that China's 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. 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. 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 four financial priorities.
Thank you. The second question maybe 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, Tengiz, because the characteristic that the free cash flow, once that they come on stream is big and is really very long duration that it can last then. I think at the time when you're sensing the project, you accept a lower return. I mean, even without the cost overrun that the return would be low. 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?
If you does, what is the minimum that you need in order for you to say yes, you get the go ahead and be able to proceed with those? Thank you.
Thank you, Paul. If you think back to our energy transition spot, like we made it very clear that our expectation was that our new energy businesses would compete on return on capital employed and returns themselves. 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. for 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.
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. As from a renewable fuels 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. That's the 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 U.S. , and we're 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. It makes sense that that would come first in the evolution of our New Energies businesses. When you're building a CCUS business, you wanna start more thoughtfully because there's an issue of building an entire value chain that's necessary. 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. We are doing a very good job of that today. On the hydrogen side of the equation, you're likely gonna follow the natural gas value chain, but you're gonna be very careful until you can figure out how to transport gas and make it economic.
That's why you're seeing those more back-end loaded. We are well on pace to our, you know, $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.
I'll just go to the traditional business. Look, we've always had more projects in the upstream than we would fund. I mean, you're trying to fund obviously well above the cost of capital. I would say 30+ years in the company, that spread is higher than it's ever been. The only way to get return on capital employed up to 12% at $60, now we were above that last year, but now 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. This is all about, again, how you invest less capital to achieve your business objective. I think we're just seeing it. It's a mindset change.
Look, it was forced on us in some ways by the market. When you're an underperforming sector for 10 years, you got to change the game, you got to change the outcome. We have changed it. 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. That's what we have to get and connect with investors. These are different company. We're a different company. It's a different portfolio. You can see our results quarterly because a lot of it is short cycle. 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.
Can I ask that given your cooperation target is 12% or higher on, [inaudible] , should we assume that the minimum requirement for your new business venture, those projects on a standalone basis need to be in excess of 12%?
You should not assume that. It's a function of, you know, Permian's 30%. As you know, we're managing a portfolio of businesses. We talked about inorganic, which will have different characteristics. You should assume that we're gonna get to 12% at $60, and we'll find lots of ways to do that. Thanks, Paul.
Guy up here in the back.
Thanks, Mark. Thanks, Pierre. 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, you know, PRRT, et cetera? The second was just what the tax position around TCO is as well going forward. I mean, clearly, you've been, you know, investing very heavily. I would presume there's been a benefit of allowances as a consequence in terms of the, you know, cash generated and effectively returned to you. Again, it's the question on taxation, et cetera, in that region. That's it. Thank you.
Thanks, Lucas. 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. We will one day. It depends on future prices, as you'd expect. There's full tax transparency in Australia. 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? It's gonna have its tax return in Kazakhstan.
You're right that there were some tax benefits that were accruing as we were constructing it. Again, there's the 15% withholding tax, which is what you really see when we receive the dividend. The tax benefits are kind of part of the cash flow within Tengiz, which is a separate company. Again, what we receive as a shareholder is the dividend. We've shown that we expect that free cash flow to grow, you know, to $5 billion at $60 Brent, and that'll come back some of that. Well, that's our share. That'll 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'll 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 assumption on cash flow in terms of Australia, at what point do you actually start paying?
That's not something I'm gonna disclose, 'cause those are all uncertain, and it's gonna be when all those things play out, and there's a very rigorous, you know, approach with the tax authorities, and it's based on the actual returns. It's not something that it's even worth speculating about. It'll happen when it happens. At that point in time, it'll kick in. Thanks, Lucas.
Just keep on coming. Keep on coming this way. Right here. Thank you.
Thanks. 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? 'Cause it does seem like it's a touch lower. I think if you do the math, our math at least was $32 billion of CFO in 2026. I don't know if that number's right, but in terms of your outlook, has it changed at all? Secondly, on CapEx, I know it's a tight range, $15 billion-$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? Thanks.
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. The bottom end of the range, which we went actually below, reflected a tougher time in the cycle. Yeah, 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. As you said, we have inflation. I think I'll take your detailed cash from ops question offline and work it 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. Some are higher, right? Our gas price, we talked about that, is higher. International LNG price is higher. There's some puts and takes in that. I think we can reconcile all that probably offline.
Over here to the...
Hi, John Royall from JPMorgan. 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, dividends, you know, in total dollars would be less than 6% growth. Is that a case for potentially accelerating the pace of dividend growth? I realize it's a board decision, but, you know, 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. Just the pacing of the dividend relative to free cash flow growth, I guess it gets into dividend versus buyback.
Well, let's go back to, I think, Paul, it 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 and recession, might be easier to answer the question. The reality is we're designing to do this through the cycles.
We intend to have leading dividend growth, we've had leading dividend growth. For five years, we've been twice our nearest peer. That means there are three other peers who are even further from us, I think we know what a lot in the industry did. We protected the dividend. We showed the two year stress test at $30, our investors knew their dividend was safe. We increased it actually 8% right before COVID, 4% through COVID, and then 6% earlier this year. 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, you know, the high investment levels that we've done. We have to factor all that in.
We have to make a recommendation to the board. I wanna be very clear, we intend to lead in dividend growth, and we have. We wanna keep all of our portfolio managers who are focused on the dividend, very happy. On the other hand, we're trying to attract, growth investors and value investors and others, and so we really have a balanced approach. We gotta look at our competitors, other uses of cash, and everything that you'd factor into it. Free cash flow is a good indicator of our confidence in continuing to lead in dividend growth. I wouldn't try to infer, you know, any specific number, and it's really not a decision for us, it's a decision for our board, as you say.
Okay. Thank you. 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 2022, 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. When you talk about the $50 notional, kinda what are the downstream assumptions there?
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.
Yeah.
You're calculating for the oil price, but you're letting everything flow. Our actual 2022 breakeven was well below $50. If we normalize 2022, 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 for natural gas, mid-cycle margins for downstream, obviously then you're going to be closer to that $50, and it bounces around. We use $50 as a notional number, and we can take you through all the numbers. I was referring to our actual 2022 breakeven. Oil breakeven was much lower because other parts of the business were above mid-cycle.
Right. She's coming. Oh.
Okay, thanks. Ryan Todd at Piper Sandler. A question on the downstream investment at Pasadena, the expansion that you have going on there. Is that, you know, 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?
I think all the way back. I think we might be the only company to have purchased a refinery in the not-too-distant past. The logic in the acquisition itself was to really serve three value chains. One was two refineries together in the U.S. Gulf Coast, Pascagoula and the Pasadena refinery, because you can trade intermediates and schedule turnarounds and things like that. We also had 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. 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 put more of our Permian production through that particular facility, taking it up to 115,000 barrels a day. That will be a good return project.
It was always envisioned as part of the transaction. When we acquired Pasadena, it was with the intent down the road to do this modest investment to have it fit the Permian better.
We wanted to operate it long enough to make sure we knew how to do the investment with confidence. That's what we've done.
Thanks.
Thank you. Over here. Then we'll come up front, Paul.
Hey, Devin McDermott with Morgan Stanley. I just have a quick one. Pierre, you mentioned 10% OpEx reduction over the forecast period, you all have been, I think, very good versus peers in 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? Are there more cost-cutting and efficiency opportunities that you have in the plan?
Yes, it's, some of it is mix shift, some of it's growing barrels in areas where we already operate. We're gonna have more barrels in the Permian, more barrels in Tengiz, you know, even Gulf of Mexico. We transformed our organization, you know, different ways of working, digital, I mean, all of that. 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.
Paul, you had a question.
Yeah. Yeah. Hi, just a quick detail question, but are you guiding to disposals still?
The guidance for this year is up to $1 billion.
Up to.
assets in the public domain are interests in Alaska and Myanmar, which we've talked about previously.
You know we've historically averaged about $2 billion a year. We'll continue to high-grade the portfolio over time, but as Pierre said, it's under $1 billion for this calendar year.
Got it. Thanks.
Up here, front.
Thanks, guys. I apologize for the follow-up. I just wanted to check a little bit of math. The 10% CAGR, just eyeballing the charts, actually looks more closer to a 15% CAGR. Is that right?
It's higher than 10%. It's greater than 10%.
Okay. On cash flow then, that's about a 5% CAGR. Is that right?
On?
27 goes to 37. 17 times-
Yes. It's about $10 billion of free cash flow, absolute free cash flow growth.
15% CAGR on free cash flow.
I'm not gonna-
5%-
You know, we like to keep a little something. We like to give guidance that we deliver on, we show you kind of the numbers, same thing on production. you know, we're gonna focus on 10% 'cause things happen. yeah, 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 can get $3 billion from Permian, you get one and a half billion to $2 billion from Gulf of Mexico. Geismar, Petchem, you add it up. It's pretty straightforward. Self-help's in there too.
Hence the confidence.
The reason I asked for the clarification is it's a dividend question, right? It looks like the cash flow growth then is about 5% CAGR. How do you think about dividend coverage as we think, try and gauge what your dividend growth could look like in absolute terms? Thanks.
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, when we were winning investors. 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%, while when we were still capital and cost discipline before the industry started investing further. All those metrics are very favorable. If you looked 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? 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.
Yeah, I would just build on the confidence theme. When you have the 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. You can see that in the numbers that we've presented. I wanna... Go, you wanna go?
No.
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, just wanna 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. Thank you again for joining us. It's great to be with you all.