Chevron Corporation (CVX) Earnings Call Transcript & Summary

Good morning. I'm Roderick Green, General Manager of Investor Relations. Welcome to Chevron's 2022 Investor Day held here at the New York Stock Exchange, marking our 101-year anniversary as a public listed company. Before we begin, a few important reminders. Please take a moment to locate the nearest exit. In the event of an emergency, the event staff will provide further instructions. And please, silence your cell phones and other electronic devices. Please be reminded that today's presentation contains estimates, projections and other forward-looking statements. These statements are subject to contain risks, uncertainties and other factors that may cause our actual results to differ. Please review the safe harbor statement on the screen and available online. Today's meeting format will be different from prior years. There will be 4 sections, a corporate overview, followed by a review of our operating business lines. Each will start with a 5-minute presentation from our executives, immediately followed by 40 minutes of Q&A discussion with sell-side analysts. The full presentation is available on Chevron's website. Now I'd like to introduce our Chairman and CEO, Mike Wirth; and our CFO, Pierre Breber.

All right. Thanks, Roderick. Good morning, and welcome to all of you in the room. It's really nice to see you in person again. And of course, for everybody's tuning in on webcast, we've got accustomed to this. I hope that we'll see you here in person in New York in the not-too-distant future. We're excited to be at the New York Stock Exchange, where we began trading as a public company over 100 years ago. We plan to be here last year, but our -- for our centennial celebration, but those plans, of course, changed like so many others during the pandemic. The past 2 years have reminded us just how vital energy is to modern life. We saw it in 2020 when economies around the world were locked down for much of the year, yet more than 90% of pre-COVID oil supply was still required to provide essential goods and services. And we see it today, with strong demand driven by recovering economies and fresh concerns about the importance of investments to ensure affordable and reliable supplies. The past 3 years also reinforced that the future of energy is lower carbon. We saw it in Glasgow, in Houston and here in Chevron as we continue to develop lower carbon energy solutions. As I reflect on the last century and the last year, I'm proud of what we've achieved, and I'm excited for what lies ahead. Our strategy is straightforward: lead in traditional energy by investing in advantaged assets with capital and cost discipline, while maintaining a strong balance sheet and rewarding our shareholders. And lead in lower carbon by being among the most carbon-efficient producers and growing new energy products to leverage our strengths to deliver lower carbon energy to a growing world. Higher returns, lower carbon, we must deliver both, all with the overarching goal to sustain financial performance in a lower carbon future. We're a much better company than we were just a few years ago. At whatever price you assume, whether the $100 we saw early last decade and again recently or closer to the $60 we saw for most of the 5 years before COVID, chevron expects to generate more cash for shareholders because we're much more capital and cost efficient. We can grow our business with less capital. And with a focused portfolio and continued self-help, we expect to drive unit costs even lower, leading to higher returns and cash flow. And we intend to keep getting better, extending our current capital guidance another year and targeting decreased cost per barrel of over 10% because capital and cost discipline always matter. As a result, we're raising our return on capital employed target to 12% by 2026 at $60 Brent nominal. ROCE is expected to increase as we reduce costs, expand margins and invest in our highest return projects. Operating cash flow per share is projected to grow at a 10% compound annual rate over the next 5 years, benefiting from higher returns and steady buybacks. Higher returns, more cash and fewer shares, the benefits are expected to accrue to shareholders. We've proven we can do this, and we're confident in our plans to continue to do so. Last fall, we announced new and updated targets to reduce the carbon intensity of our operations, an aspiration to achieve net zero upstream Scope 1 and 2 emissions and issued guidance for the growth of our new energy businesses. Today, we're reaffirming these and our team will update our progress in the other sessions. We intend to be a leader in carbon-efficient production of traditional energy, while building new energy businesses where we have competitive advantages, expect attractive returns and see the potential for much larger scale in the future. We believe we have the capabilities, assets and customer relationships to lead in the energy transition, helping to lower our emissions intensity while meeting the energy needs of a growing world. Now over to Pierre.

Thanks, Mike. Our financial priorities are consistent, and they've guided our actions through several commodity cycles, including the last one. The results speak for themselves: a dividend per share that's doubled since 2010; investment program that's at least 20% more capital efficient than it was pre-COVID; a balance sheet with a net debt ratio comfortably below 20%; and another increase today in our annual buyback guidance range. You know what to expect from us. We have a formula that works. Chevron is on a different path than others in our industry. With an industry-leading balance sheet and a flexible capital program, we've proven we're a safe haven in the last downturn. And now with the cycle up, we have the highest leverage to oil prices among our peer group. It shows in the numbers. At $50 flat Brent for 5 years, we can grow the dividend and maintain buybacks, while our net debt ratio is expected to move back into our midcycle guidance range of 20% to 25%. And if Brent nominal prices averaged $75 over 5 years, we could increase the dividend at higher rates and buy back more than 25% of our shares outstanding. Future prices are uncertain, our track record is not. In both high and low price environments, we intend to manage risk and reward shareholders. Back to you, Mike.

All right. Thanks, Pierre. To sum it up, by being more capital, cost and carbon efficient, we expect to generate more cash to support a growing dividend, investments in traditional and new energy businesses, a strong balance sheet and steady buybacks. We believe this is a winning combination for shareholders. The last 2 years have been some of the most challenging this industry has ever seen. We came into COVID in a strong position. And today, we're even stronger. We've transformed our organization, integrated Noble Energy's people and assets and formed Chevron New Energies, which is steadily building momentum. We protected the dividend when prices crashed. We're the first to announce a major acquisition, developed and approached the energy transition that seeks to create value and leverage our strengths, including the acquisition we announced yesterday, and we continued to maintain cost and capital discipline. You've seen how we've led this industry during the past few years. I'm optimistic about the future of energy, the future of Chevron and our continued leadership in the years to come. Now let's move into Q&A. Can I ask for 1 question and 1 follow-up. We've got microphone runners. And if you can raise your hand, we'll get a microphone to you. Please introduce yourself and who you represent, so that the people that are watching online know who they're hearing from. So we'll come right down here on the aisle to begin. Second row, I see Mr. Sankey has a pen in the ear.

Could you talk a little bit about the Ukraine situation? I would assume that you guys feel quite defensive regarding your exposure compared to, say, the big European majors. And I just wondered if there's anything you could add in terms of financial flows? Or what on earth is going on there? And if there's any lag that you can share in what's a very confusing situation?

Yes. Thanks, Paul. So obviously, it's a tragic situation as you watch this unfold. We don't have direct exposure in Ukraine. We don't really have much exposure in Russia. The Caspian pipeline being really the only asset that we have that is in Russia. So we don't produce and sell out of Russia. We really just transit through Russia with our production from Kazakhstan. The actions that have been taken thus far by governments in Europe, the U.S. obviously, and others have been crafted in a way to try to create the desired outcomes and yet not impede energy flows. I think there's a recognition that's coming into this. Energy inventories were low, supplies were tight and a very conscious effort to not impose further energy cost pain on the global economy. Now there can be secondary impacts of all these things, right? Shipping rates have gone up, insurance typically follows marine movements in the black sea now. They're becoming a little bit more carefully choreographed. We have not seen any interruption of physical flows of oil or gas, at least none that I'm aware of. But there are certainly a lot of people who are concerned -- Urals crude discounts have widened out, as you all have seen. So we're beginning to see the effect of these things show up in the marketplace. As I say, we are relatively less affected, I think, than most others in the industry. Colin -- when Colin comes up with Jay, he can talk a little bit more because overseas supply trading, shipping, and his team's got crisis management team stood up and ongoing daily discussions and all the things we're seeing around the world. But at this point, relatively little impact on us. Third row, left. Ryan.

Maybe a follow-up on that, at least thematically. I mean ongoing events over there in Europe...

Can you just introduce yourself?

Oh, sorry. Ryan Todd, Piper Sandler. They're already having a meaningful impact in a pretty short period of time, at least in rhetoric, in terms of how Europe and many others in the world will look to source their energy, whether it's an acceleration in the renewables or diversification of natural gas supplies that has a potential for meaningful impact in energy markets, particularly global gas markets. So I guess, from your point of view, what do you see as the potential impact to global gas markets over the next 5, 10, 15 years coming out of this? And how are you positioned to take advantage of this? In particular, I guess I would highlight Eastern Mediterranean gas, but what potential impact? And how would it potentially impact the way that you think of allocating capital?

Yes, Ryan, I think it's early days to really have confidence in how energy policy is likely to evolve as a result of this. My view is that many countries have had imbalanced approaches to energy policy in the recent times. And as you look at balancing out the needs of an economy for energy, the reality is about diversity of supply and energy security and then also environmental objectives. So those need to be considered in a balanced frame. I think the frame has been a little bit unbalanced in many instances, and we're seeing now the reliability matters, affordability matters and, of course, ever cleaner matters. And we talk a lot about affordable, reliable and ever cleaner. In many discussions I've had, the first two get brushed by pretty quickly in pursuit of the third. And I think it's going to be important for policymakers to consider how we balance all of those as we go together, right? We view there being a very important and growing role for gas in the mix, particularly as you see more wind and solar, you need some sort of reliable generation capacity to deal with the intermittency that we're going to see increasingly, and we see it in California right now, where a lot of us live, pretty regularly, when you need to have natural gas generation spin up to keep the grid balance. So I think it's a good future for natural gas. We have the big position in the Eastern Med. I'd encourage to ask Jay about that. There's even some news this morning over there on some of the commercial activity to build new markets, and we've got a number of other things that we're working on there. And of course, we've got a really attractive exploration blocks in further west in Egypt in the Mediterranean that we shot seismic on. I think the first well goes down this year. So we see a bigger role for gas in the future and Eastern Med is certainly an important asset for us in the portfolio. Maybe just pass the microphone on, and that'll -- to Roger, and we can just keep it efficient there.

Roger Read, Wells Fargo. I guess my question really to you, Pierre. As we look at the 5-year at 50 or 5 years at 70 to kind of give the upper, lower bounds there. What is included in that in terms of how we should think about it? Is it a flat price, 70? Is there an inflation adjustment? In terms of your assumption of being able to keep $50 is the breakeven over that many years, what else is included in that in terms of the base case assumptions?

Thanks, Roger. So on the $50 case, it's -- again, these are nominal prices, so there's no inflation. Capital program is essentially the same. And what you see is dividend increases through the 5 years, just like we've increased dividends through COVID, right? Our dividend is up almost 20% since COVID, 6% earlier this year. So you'll see dividend increases. And you see buybacks. So you're right, our breakeven is around $50 to cover our capital and our dividend but we're well below our mid guidance range on debt ratio. So we can actually, as we've said, we intend to maintain the buyback through the cycle. And so in that $50 case, you maintain the buyback, and you lever back up into that 20% to 25% range. So that's why you see buybacks in that case, even though at 50, technically, you're not generating it from your cash, you're doing it off the balance sheet because we're well below our guidance range. The high case is actually 75%. We did it asymmetrically because it feels like there's a little asymmetric upside to the downside. And you have a very similar, again, capital program in that outlook, and you have higher dividends. And then, of course, you have the potential and the capability to buy back 25% of the shares outstanding. And so it's really meant to emphasize our financial framework and how we will return cash to shareholders in a mid-case of $60 flat and then testing it on the downside and the upside. And the message is we're going to return a lot of cash to shareholders over the next 5 years.

Okay. No follow-up? Okay. Let's come to this side of the room over here. Paul, on the aisle, and then we'll...

Okay. Paul Cheng, Scotiabank. If I could, 2 questions. One, related, Pierre, when we're looking at your presentation, it doesn't seem like you want to put money on the balance sheet at this point, given you already...

Paul, can you hold the microphone just a little...

Given you already have a decent balance sheet. So if oil prices stay somewhere close to where we are, you're going to generate far more than what even the $10 billion of the buyback you will execute. And so from that standpoint, how should we look at the incremental cash? Can you share with us what is the split between the balance sheet and on the incremental cash return? The second question is for Mike. You have a pretty well-defined plan here. But the world is a volatile world and unpredictable. So when you're looking at your plan, what's the biggest risk factor or that can you say, "Oh, I mean this is too much of unknown that it could really swing and change my time."

Okay. I'll start, Paul, on the first one. We're sizing -- we just increased our guidance, essentially doubled it on the buyback, the $5 billion to $10 billion a year. And we could go bigger than that, clearly. We're setting the buyback at a level that we can maintain across the cycle. And so the idea is not to maximize buybacks while we're generating this kind of excess cash. It's to set at a level that when the cycle turns and the cycle will turn, we'll continue to do -- to maintain buybacks. And again, to Roger's question, we show that in the $50 downside case where you're doing it to relever back up into your preferred range. So the -- in the short run, it goes to the balance sheet, that's not by design. I mean if it turns out that our cash generation exceeds our now revised guidance, which we increased it just back in December and increased it again, then you're right in the short run, it will go to the balance sheet because we want to maintain this at a level that we can continue. But over time, it comes out of the balance sheet and it goes back into the -- back to shareholders. So again, we're not changing our gearing ratio guidance, the 20% to 25% that holds. We're below that. We were below that at year-end. We might go below it a bit. That's temporal. There's nothing you really can do in the short term. The cash comes in. Let's talk about the 4 priorities again. We just increased the dividend 6%, up almost 20% since COVID, right, doubled since 2010. We have a capital program that's within the low end of guidance, up 30% from last year, but near the low end of our $15 billion to $17 billion guidance, which we extended again a year. So we're not going to increase capital. We're already increasing at 30% versus last year. Go to the forward, while we'll just increase that, where the cash goes in the short run because you're not going to change the other priorities, it's going to go to the balance sheet. But over time, it comes out of that and it goes back to shareholders.

Paul, on risks, your question. In the short term, the thing that I pay the most attention -- that I worry the most about is cyber. It's a never-ending challenge out there right now. And so we've increased our resources and commitment to focus on cybersecurity steadily over the last decade or more. In the environment we're in right now, we're in a high-risk environment right now from a cyber standpoint and we're an industry that is a high-profile, high-value target for bad actors. So that's the thing in the short term that I probably would say in my view, the risk I worry about the most. Longer term, is you missed the call on the future. And we do the best we can to monitor signposts across a wide range of indicators on supply demand, technology policy, all the things that affect the magnitude of energy growth and economic activity in the world and the shape of demand over time. And then also, of course, what are the economics of supply. And that's in both traditional energy and these emerging energies. And so we lay out a central long-term strategic scenario and then we run other scenarios around that. We use that to identify the signpost that would tell us some of our assumptions need to be adjusted. And so to me, during my career, there's probably never been a wider range of opinions you hear externally on what the future would look like. And frankly, I think even internally, some of our ability to see the future is more challenged than it's ever been. And on the one hand, you can say, "Okay, wow, if you miss some technology that really changes the demand for oil and gas, that might be a big risk." The flip side of what we're seeing right now, if the world chooses to underinvest in oil and gas for a number of years for whatever reason, and you can -- you guys are familiar with all the reasons that could happen, we could be in a scenario where the demand really does outstrip the supply, and that presents a different set of challenges. So I think I would say longer term, it's just -- it's really being diligent -- we have to be diligent about monitoring these signposts, not drinking our own fluid, not think we know more than we really do and being humble enough to adjust our strategic planning scenarios when we're presented with evidence that suggests that we're seeing a trend evolve a little bit differently than we had initially envisioned. Yes, let's come right in front of Paul to Phil.

Phil Gresh, JPMorgan. First question for Pierre. On the ROCE target, it's going to 12% from 10%. So it sounds like a 20% increase, I think, on the same price deck, so I was hoping you could elaborate on some of the drivers of that. The second question is just, you gave a 50 case and a 75 case. It seems like you're not too concerned about any inflation risks in those 2 scenarios, but I'm curious as we look where we are now, what is the scenario where you'd be more concerned about inflation risk, whether it's on the OpEx targets or the CapEx targets?

So on the CapEx in COGS, we do our planning assumption assuming a cycle and the business is cyclical, supply and demand get out of sync at times. And you saw that on the downside in COVID in 2020, and we're seeing that now here in an upside scenario. And so we're not going to change our COGS every time there's a cycle up or a cycle down, we're trying to kind of view what we think costs will do over time. So that's what's embedded in our $15 and $17 billion guidance? It's that there's going to be an up cycle, and there's going to be a down cycle and on average will be okay, and that's what's embedded in our OpEx per barrel. And we just said guidance of the 10% reduction in our OpEx per barrel. That includes without upstream and downstream, and we'll -- Roderick and team will help you be able to triangulate around where you see those volume numbers in our reports. It's essentially our wholly owned upstream and downstream barrels, excluding affiliates. In terms of return on capital, we've been on this journey. It's higher returns over carbon. That's our message. I saw a little bit more on lower carbon yesterday, I mean we've been working hard. We never said 10% was our goal. So you're right. 2 years ago, we showed it at 60, and it was 10%, but it was 2024 at that point in time. Last year, we went to 50 because it was a very challenging time. We're back to 60, you can compare all those numbers. But as you get another year, the high-return investments that we're doing in the Permian and other places accrete to return on capital employed, some of the low-return investments that are working off come off the balance sheet. The self-help that Mark Nelson downstream are doing, more of that comes in. And you see some of the -- again, the traditional growth shows up in our business, too. So it's really -- it's a continuation of the journey we've been on. And as we now -- 2 years from the last time we showed the $60 case, you just see the accretion effect of high-return investments coming on the balance sheet historical low return, high cash, but low book returns coming off. And over time, we work that in a lot of self-help working costs and other parts.

Yes, front row over here?

Sam Margolin, Wolfe Research. My question is about your production growth targets. In the past, M&A has contributed to production, not necessarily in the target, but through time, historically, it allows you to offset old production with new production. And M&A has been a very consistent element of your strategy and your stock is at an all-time high today. So presumably, it will continue to be. So the question is, as we think about the production target and the role M&A has played in the past, do you think that's something that will continue? And what sort of asset classes attract you right now?

Yes. So Sam, just to restate what I've tried to say many times, production is an output, not a target, right? The goals are financial performance and returns. But the production is an output. M&A has played an important role in that over time, not necessarily to maintain progress towards some target, but really, we've turned the portfolio, right? We've gotten out of things that no longer compete for capital within our business. We've added things that are more attractive investment opportunities. Noble Energy being the most recent example of that. A few years ago, there was some anxiety about concessions expiring. This is all part of how these businesses evolve over time. So M&A will continue to be part of our playbook and has been for decades. As you say, we'll be disciplined. We're not necessarily asset class hunters. We're value hunters. And so we'd look to strengthen our portfolio with assets that would compete for capital. We've got some strong, and I would argue, relatively concentrated positions in certain areas of the world right now. And so adding some additional basin exposure is a consideration. There's a whole host of things that we would look at there. But I'm not going to say we need more deepwater, we need more LNG, we need more unconventional that might point you in a direction that's misleading. We're going to look for things that will compete for capital. We'll add value that have scale. We do things that scale very well and that we'll deliver strong returns over time.

If I could maybe just add and point out, I think it would be good for Jay. In the appendix, we put a 10-year outlook of our upstream potential. We have a lot to choose from as we go and we can do it very capital efficiently. I mean we can sustain and grow the traditional business at lower capital levels than at any time in certainly my career's time.

Yes. That's an update of a slide we showed a couple of years ago that's got a 10-year outlook for production capability in the appendix of Jay's deck, and Jay can answer your question. Let's go right over to Neil then and then hop towards the back.

Neil Mehta here with Goldman Sachs. First question is around Tengiz. And just an update on the project. It looks like this morning, you're indicating that no major disruption, and that you're on track. How do you think about the last gating items to get this to full operation?

Yes. I'll give you a quick answer on that because I think during the upstream session, it would be better for Jay to give you a more detailed answer. But we have -- the people on the ground there have done a remarkable job in dealing with the pandemic in a country that didn't necessarily have the same -- preparation that another part of the world might have, and our people have done nothing short of miracles in terms of keeping tens of thousands of people tested safe productively at work. Progress over the last quarter of last year was -- productivity was as good as we've seen since the project began. January was a little bit challenged with some of the unrest that we saw in the country. That has stabilized now. We're back at work, and we still feel good, 89% completed at the end of last year. Jay will give you a little bit more, but we haven't changed schedule or budget guidance on that.

The follow-up question, Mike, it is my [indiscernible], but has there been any discussion with the administration in light of heightened geopolitical tensions and the need potentially for U.S. barrels to satiate the world market about the Permian growing? And do you see a role for the U.S. from an energy security perspective in that regard?

Yes. I really don't want to comment on discussions with administration beyond saying that we have a lot of common ground with the administration. In the early months, I wish there had been more dialogue than there was. The administration had their priorities and interaction with us was lower on the list than some other things. I think it's going to be important for our country and for other countries around the world for this industry and governments to try to get on the same page on what good energy policy looks like. I think we've had a couple of decades of frankly, you go back 2 decades ago, and we were in a -- it was a concern about resource scarcity, the last decade plus, we've been in a world of resource abundance. And I think energy policy has failed to recognize some of the underlying realities in terms of how it is connecting to security and economic success. So we hope to have good constructive dialogue with this administration going forward. We'll go to Biraj right here, so...

Just what I can add. I mean -- and we gave Permian guidance, it's growing 10%. I mean we're growing our production.

Investment production activity all up in the Permian significantly. Just come in the front row here, Biraj.

It's Biraj Borkhataria, RBC. A question on LNG, based on some of the macro comments you made, you can quite conceivably make a very constructive case for international gas and particularly LNG over the next decade or 2. Your LNG position is very concentrated, also become a good cash cow for you. Can you talk about your willingness or interest in growing that business over time because there's some options out there?

Sure. There are options out there. There's been some speculation in the meeting on our participation in some of those. Look, the LNG projects have to be low cost. Over time, there are cycles in this business, and we would not make an investment predicated on the kinds of market conditions we see today. You've got to look through that to long-term full cycle market conditions, and you got to invest in projects that will compete well through the cycle. We walked away from a project in British Columbia. A good project, great gas resource, really great work by the teams to develop the best possible design for that project. And at the end of the day, we were not convinced it would compete with Gulf Coast-based supply, for instance. And so rather than proceeding with the project that we felt was less competitive, we chose to walk away from that one. So we'll look for things that we think compete for capital in our portfolio and compete in the world.

Just one follow-up. On your portfolio carbon intensity target, minus 5% reduction by the end of the decade. Is it a fair characterization to say that the business mix between oil and gas, under those assumptions, is roughly similar to what it is today by the 2028 target?

Yes, I think that's -- the business mix on things like that changed relatively slowly, Biraj, absence of large transaction. I mean these things, they kind of it's a lot of big numbers and incremental investment and change around them. So it wouldn't be a massive change in the oil and gas mix. Let's go...

In the 10-year outlook, we don't have any greenfield or new LNG. We have Eastern Med expansion. And of course, Permian is a big growth in oil and gas.

Oil and gas. Back in the aisle here, please?

Jason Gabelman from Cowen. And I appreciate the Q&A-heavy format. I wanted to ask about free cash flow, which guidance wasn't provided. In this presentation last year, you got a 10% CAGR on absolute free cash flow, I think, at a lowered oil price. So how does this updated plan compare to that? And specifically, how do TCO distributions contribute to that free cash flow? I'm assuming it's kind of back-end weighted given the ramp-up in TCO? So a color there would be helpful.

Yes, that's a good CFO question.

Thank you. Yes, Jay will show a chart that covers free cash flow. You've already seen this posted, and that's a good -- that's 100% TCO free cash flow. That free cash flow over time will be in the form of dividends, subject to the TCO Board's decision, and then loan paybacks and the loan paybacks have been disclosed in our 10-K. So there's strong free cash flow generation coming out of TCO. We just do 1 cash flow sort of target. You're right. We've moved around from free cash flow, cash from ops. It's all better. I mean we're more capital efficient, we're more cost efficient. We haven't changed our CapEx guidance, our cash from ops guidance is greater than 10% per year compounded over the next 5 years. So I think we've given you all the pieces we're happy to walk you through it. We just don't want to give free cash flow and cash from ops, too many numbers out there. It's -- again, we say we're a better company than we were a few years ago, we were capital position more cost efficient. We can sustain and grow this Enterprise at a lower capital level. We gave a 10% target on OpEx per barrel. So all that means more free cash flow. And that's why you can see, even in the $50 case, we continue buybacks, $75 case potential buyback, 25% of the shares outstanding.

Pierre, on the fourth quarter call, I think you touched on tax. A slight shift in our tax position, maybe you want to just clarify that again in case people didn't catch that.

Yes. Thanks, Mike. So yes, so there is one thing, as you compare this year to last year. So last year, we were at 5%, now we're at 60%. Our tax paying position has changed. It's a good thing. We've worked through our net operating losses. We guided to that on the fourth quarter call. So you'll see a little bit lower -- our cash sensitivity as a result is now matching our earnings sensitivity. Before, it was a little bit higher because we were using prior net operating losses. And those are largely getting consumed this year.

Okay. Jeanine?

Jeanine Wai from Barclays. My question is for Pierre. Pierre, I'm just wondering, the net debt target -- soft target of $20 billion to $25 billion, it's still the same. Over the past 2 years, it really showed us that the world has changed. It's been more volatile. Crude prices are probably going to still be very volatile. But at the same time, Chevron has changed, and you've repositioned the company to be able to thrive in a much lower environment. So I'm just wondering why 20% to 25% is still the number? I guess, in our view, maybe skew a little lower. And I guess this also just kind of goes into everybody's back solving with the free cash flow and buyback and the net debt-to-cash. So just any comment on that would be great.

We haven't changed. It is soft guidance, and it's a range. And when I became CFO, everyone asked the question, and so we gave the guidance. But it reflects that we're -- our breakeven is a lot lower, that we don't have long-dated major capital projects. If you go back to a prior time where we're constructing major capital projects, we get 4- or 5-year commitments. I would say that we would have kept a stronger balance sheet and we did, in fact, and thankfully we did. But when your breakeven to cover the dividend and capital is 50, when you have a flexible capital program and you can -- and we did, right? You saw it in 2020, when we started the year with a $20 -- a $20 billion capital program and ended the year at, I think, 12 or something like that, that you can flex it, then you don't need to put that much on the balance sheet. And again, we're going to be well below it right now, that was the other question. But over time, rebalancing into that range. And I think that reflects my conversations with investors and what is an efficient capital structure. So if circumstances change, we can change that guidance. But everything we're talking about today is only getting better; more capital efficient; more cost efficient; better growth, traditional business; better growth, new energy business; progress on your energy business. All of that from my perspective and from our shareholders' perspective is this is a reasonable guidance. And again, it gives confidence that the buyback can be continued through the cycle because we can relever back up into that range when the cycle turns.

It's Lucas Herrmann at BNP Exane. Two questions probably directed to you, Pierre. The first is around -- well, both around CapEx. The first is, the last few years, it's been very clear that the absolute CapEx that goes through your cash flow statement is clearly a lot lower. It's been a lot lower because of changes in the headline that you present each year. As you look out over the next 5 years, the guidance is 15% to 17%. I just wonder how much about is company, how much is associated, so I can actually start getting cash flow statement that resembles something that you present? And the second, just staying with CapEx, Biraj alluded to it in some part, you have a fantastic base business, which actually doesn't have huge capital requirements. Can you just give us some better indication when I think about upstream, in particular, as to what proportion, absolute or percent of the CapEx, is effectively unit base sustenance? And what -- I don't want to use the term growth because -- but what's the capital that's available as a consequence to drive the enhancement and returns? Unfortunately, we all model on the basis of barrel and capture, whereas absolutely, you think about in the terms of capital in a higher return, just that's not the way the modeling works.

So we gave 2 years ago our affiliate profile, and it still looks good. I mean, it only went to 2024, just to answer that question. I mean, so clearly, our noncash capital. So again, the capital is you don't see on the cash flow statement, but again, it all works through because you don't see the dividends also, right? So it all works out the same. But it's going to come off. And we've said our Tengiz capital will come off about $2 billion, so I think we're at $3.5 billion affiliate. So something around $2 billion, $1.5 billion to $2 billion is probably a good number. And I again ask you to look to our investor material from 2 years ago at this meeting, and we provided that. On your second question, and we don't really think of it this way, but we know it's important to answer. And again, we are at least 20% more capital efficient. There's lots of ways to measure capital efficiency. But if you look at sustaining capital, Tree Noble, we said we were about $10 billion, Noble was, I think, $750 million or so. We would estimate that number at about $9 billion. So we define that does not include exploration, doesn't include, obviously, the concessions that are expiring, but it's the capital to maintain production flat with that remaining portfolio for a number of years. And of course, so it doesn't include downstream and chemicals and corporate and a few of the other things. And so again, you're going from over $10.5 billion down to $9 billion. So if you look at our sustaining capital, we're 20% more capital efficient. If you look at it relative to our cash from ops, you can triangulate around lots of different ways. I really encourage you to ask Jay Johnson and Mark Nelson, kind of how we're doing and how we're getting more or less. And the goal is to sustain and grow the enterprise with the lowest amount of capital because that leaves more free cash flow for shareholders. And we have reinvestment in our business. That's part of having declines. If you can reinvest less and still sustain and grow more free cash for shareholders.

Okay. We've got time for 1 more.

It's Doug Leggate from Bank of America. Two questions, if I may. One is go back to the Russia thing and the second one is on the breakeven. Our folks at Bank of America are suggesting that while there are no sanctions per se on Russian production, there are de facto sanctions because companies are shying away, if you like, from trading around barrels at the otherwise have used. What is Chevron doing? What exposure did you have? And how is that changing? My follow-up is, if I look at Slide 10, Pierre, on the dividend side, it looks further 50 or 75, the absolute dividend is kind of static more or less, which would lead me to think that share buybacks are driving the dividend growth, which is a good thing. Doesn't that mean your breakeven is going down over time? Could you clarify that?

Yes. I'll defer to Colin Parfitt on the Russian trade flows question. His team is looking at that every day, and he can comment on what we're seeing in the markets.

Yes. Our dividend is going down over time. You'd expect that more free cash flow Permian and Tengiz right through this whole time.

Dividend breakeven.

Yes.

You said our dividends are going down. You meant the dividend...

I meant our breakeven cover our capital and our dividend is going down because we're generating cash flow, we're keeping capital flat. The dividend comparison between the 2 in the $50 case, there is lower dividend per share growth, and the $75 case, there's higher dividend per share growth. But guess what, there's fewer shares. And so if you look at the absolute dollars going to dividends, they look comparable, but they're different profiles. You're buying back a lot more shares in the $75 case than you are in the $50 case.

Okay. We are right at the end of the time that we had allocated today. So I'll wrap up this portion of the meeting. I want to thank again everybody that's tuned in on the webcast. I especially want to thank those of you that came up today. It's been too long since we've seen you in person, and I hope this is a regular feature of the future. I appreciate the interest in the company. We are consistent, adaptive and resilient for more than 100 years of listing on the New York Stock Exchange. We're in the 143rd year of our company's existence. We've seen wars, famines, pandemics and all types of challenges and that our company has been able to navigate successfully through those difficult times. We intend to do the same through these sad and difficult challenges that we face today, and we intend to return more cash to our shareholders as the company continues to improve in the future. So thank you all for your time. We'll have just a quick change over here. As Pierre and I step down, Jay Johnson and Colin Parfitt will take the stage to talk to you about our upstream and midstream activities, so thanks very much.

I'm Jay Johnson, and I'm pleased to be here with Colin Parfitt, and we're here today to talk about Chevron's upstream and our midstream business. The picture behind me is the 20,000 psi blowout preventer for the Anchor project. It's the first ever to be engineered and built for these pressures. And with this enhanced capability, we're opening up new possibilities in the Gulf of Mexico. As we look forward to the next 5 years, we're more capital and cost-efficient than we've been at any time in the past decade. The total capital less than half of the 2010 to 2014 levels, unit operating costs are expected to be down more than 20% from the 5-year averages pre-COVID. At the same time, oil and gas production is expected to grow to well over 3.5 million barrels a day by 2026, with most of the growth from our Permian and Kazakhstan assets. With greater capital and cost efficiency and higher production, we expect to deliver higher returns and significantly greater free cash flow per barrel, around 3x higher than when oil prices were over $100 early last decade. While generating higher returns, we're also targeting to lower our carbon intensity. We're in the first quartile in upstream carbon intensity today, and we're making progress towards our 2050 upstream net zero Scope 1 and 2 aspiration. We're on track to eliminate routine flaring by 2030 and reduce methane emission intensity by 50% from 2016 to 2028. We plan to get there using a disciplined approach to targets flaring, methane emissions and energy management. Progress is expected to be supported by advancements in technology and greater policy support as well as by capabilities enabled in our New Energies team, including carbon capture and storage and cost-effective verifiable offsets. At TCO's FGP/WPMP project, we delivered all the major 2021 milestones despite the impacts of COVID. We expect to see a similar level of progress in 2022. Our cost and scheduled guidance are unchanged from last year's update. With construction in the final stages, our focus is moving to getting utilities up and running and completed construction on process systems. Already, we've started up 3 or 4 production metering stations delivering high-pressure oil from the new wells to the existing plants. TCO's free cash flow is expected to grow significantly by the middle of the decade, as capital ramps down and production increases. This results in a capacity for higher dividends and repayment of Chevron's $4.5 billion loan to TCO. In the Permian, we're building a business that's expected to deliver high returns and significant free cash flow for decades. With capital investment of around $4 billion a year, we expect to grow production beyond 1 million barrels of oil equivalent per day. We can do this because of our large resource base and efficient factory model. When we add royalty advantage to the scale and efficiency, we expect to deliver book returns greater than 30% and free cash flow greater than $4 billion in 2026, at a $60 nominal Brent price. At around 15 kilograms of CO2 equivalent per barrel, our Permian carbon intensity is approximately 2/3 lower than the global industry average. We're applying similar factory models to other assets to drive higher returns and lower carbon. Examples include the DJ Basin, where our latest facility design lowers costs and emissions with potential application to other onshore assets globally. In Argentina, we're leveraging lessons learned elsewhere to lower unit development costs and manage methane. And in Angola, we've reduced flaring emissions from Block 0 by over 80% since 2016, and recently signed an extension of the Block 0 concession to 2050. Standard, repeatable designs across assets with rapid adoption of evolving best practice is a key enabler to drive improved capital and cost efficiency across our portfolio. We also expect to deliver higher returns and lower carbon in the deepwater. In Australia, the first Gorgon backfill begins producing this year and is expected to cost 30% less than our budget, primarily due to subsea execution and drilling efficiencies. The Gorgon project has stored around 6 million tonnes of CO2 to date. And in the Gulf of Mexico, a steady queue of developments is expected to grow production at competitive unit development costs, and with carbon intensities that are a fraction of the global industry average. In the Eastern Mediterranean, numerous efforts are underway to unlock access to additional regional demand and increase exports to Egypt. With a large discovered resource base, growing regional demand and a carbon intensity of around 2 kilograms of CO2 equivalent per barrel, we believe we're well positioned to further expand in the region. An overview of the upstream. Now I'm going to turn it over to Colin.

Thanks, Jay. Chevron's large and diverse global gas portfolio exposed to both domestic and international LNG markets. Globally, we have 180 net trillion cubic feet of natural gas resource. And last year, we produced more than 7.5 billion cubic feet per day. To optimize, we valued -- we traded additional gas volumes, which are roughly 30% above our equity production. More than half of our gas production is in the United States and Australia. In the U.S., we have exposure to the liquid Henry Hub market. In Australia, we have mainly long-term oil-linked LNG contracts with high-quality customers. Our West Africa reduction primarily delivers into the LNG spot market in both Europe and Asia. And as Jay mentioned, we're advancing multiple options to market future production growth from an attractive acreage position in the Eastern Mediterranean. In all regions, our global trading and shipping capabilities allow us to maximize realizations right across the value chain and provide a competitive differentiation in shift in market dynamics. Now let's move to Q&A for this session. Please ask 1 question and then limit yourself to 1 follow-up.

Great. I'm just going to work right across, I'm not selective. Neil, you go first. If you can give us your name and who you work for, please.

Neil Mehta with Goldman Sachs. We asked Mike about this a little earlier, but Jay, would love your perspective on the ground in Kazakhstan and Tengiz. One is, how are you thinking about managing aboveground risk to the extent that they exist? And then from a completion perspective, things look like they're on track, but just your perspective on gating factors.

Thanks, Neil. I was able to go into Kazakhstan just a few weeks ago after the unrest that happened and to really visit with teams there on the ground and with some of the new government officials. And I think the country has settled down from what happened. And certainly, there's a lot of activity regionally, as we all know, in that part of the world. I would characterize it that the project teams have been able to recover quite effectively from the cessation of work we had about a week where we couldn't work. They've rebuilt that momentum. We had a great fourth quarter. So we were seeing excellent momentum coming out of the Delta back in the third quarter. And then they've carried that into this first quarter and it's kind of regained their momentum. And it's been really good because they found offsets for each of these things that kind of held them back, they've been able to find other ways to move forward such that we haven't changed our capital and schedule guidance at this point for the project. The work that they're doing, it's been really good on this when this project is so integrated with the existing project, the existing facilities. So the 110,000-volt power distribution system that is part of this project now feeds all of the facilities in Tengiz. And that's been commissioned and put into service, and today, the system runs on the new facilities. We have seen the new control center that will control the entire complex. We've already cut over, the field facilities are now being operated out of the new center as have the power distribution facilities. Now they're moving to the KTLs to start bringing them across. The significance of this is that it's allowing us to test the commissioning, the documentation and the handover of these just thousands of subsystems which is always a struggle for a project team. But by doing this early, it's letting us optimize the system. Everybody is getting into a routine for the real push that's going to come this year and next. And as we finish construction, as we're approaching the end, it's all about finishing these systems in the right order, handing them across to the commissioning team and then into the operation start-up team. Tengiz uses 1-team approach, and it's been remarkable watching how all these teams have worked together. I send them the same song, I get knocked down, but I get up again, and that's become the song for Tengiz, but they've just done an admirable job on the ground. So we need some running room. We need to maintain this. We've been able to work effectively with the winterization program we put in place. That hasn't held us back through the winter. And so we're all trying to be very optimistic going into this year. About 90% of our workforce on the ground in Tengiz at any point in time is fully vaccinated, so that helps a lot and it gives us a mitigation against COVID. But with all the events that are unfolding with COVID still running around the world, we just can't let our guard down. So I can't predict the future, but I can tell you there's just constant focus on maintaining forward progress. And every day, we're getting closer to bringing this online.

Jay, the follow-up is just on operations in Australia. Gorgon was running well for a while and then had some fits and starts. How do you think about it for the balance of the year? And you feel like you got some of those wiggles kind of worked out in the system?

Yes. Plants like Gorgon are large, and they're complex and Gorgon, in particular, gets a lot of scrutiny. But I think the data is really important. Gorgon has actually continually improved on its reliability. And so we've seen a significant improvement from 2017 when it started to where it is even last year. We benchmark, as we've talked about, as part of our competitive analysis. And in the benchmarking, we use Townsend. And when we benchmark both Gorgon and Wheatstone, both of those are approaching top quartile performance on reliability, against all other facilities, a benchmark in the world. That said, I get highly frustrated when we lose production and we lose cargo and we have to take these downtime during these periods of price. These are the times you want to produce. So -- but at the same time, I'm really careful because what our teams have done is exactly the right thing. They spot small issues, they take the plant to a safe state. They implement the repair and then they bring it up because I would much rather have these short things to fix problems that they spot proactively than to have them try and run through it and build up and lead to a problem. So I get frustrated sometimes like I know everybody does, but the teams that we have on the ground have run these facilities well. Every time we find something and we engineer it out of the plant, they're getting more reliable. And I expect to see us moving into that top quartile for reliability as we come into this coming year. So it actually is better than it looks many times. Yes?

Sam Margolin, Wolfe Research. This is also another version of a question that Mike and Pierre fielded about Permian concentration. And in the world today, Russia is increasingly isolated. It's a lot of energy supply. The Permian is becoming strategic geopolitically, so has there been any change in your thoughts about Permian concentration within your portfolio? And then as a related question, sort of a follow-on, the concept of exporting the gas you produce in the Permian, it's a big capital commitment but potentially delivers a lot of upside or the NPV of the asset. So any thoughts you have there, too?

Thanks for the question. I'll start with the first one, and then I'll get Colin to maybe talk about some of the gas export and how we market both the crude and the gas and gas liquids. In terms of Permian, it's an interesting field. I always used to wish for Tengiz to be in West Texas. It could be another one, that would be great. And in many respects, it is. The difference with Permian, though is it's distributed across many, many facilities. And you don't have all the production flowing through, just a few key facilities where you could have potentially incidents or problems. So when I think about the Permian, we treat it as 1 asset, but it's actually a collection of many, many assets spread over a big geographic area. The efforts that we've been able to do by linking our asset class teams together in the unconventionals and in the factory models, taking best practice from 1 field, moving it to another benchmarking. We benchmark Argentina against the Permian against the DJ Basin. All that is really helping us continue to drive for improved performance. We also benchmark against third parties and the nonops that we are involved with as well. So I like the position that we have. We've shown the growth that we expect to get in the Permian, not just in terms of the production, but in terms of the returns and the free cash flow, it's going to generate for us. I can remember not that long ago, nobody thought we could get free cash flow out of the Permian. And now you're looking at quite a different situation. But the key is to not lose the discipline that we've applied over these last 5 or 6 years to just be rigidly focused on driving capital efficiency and lower operating cost as we march that production upwards. So that's how I kind of think about the Permian and the role it plays. It's a key part of our portfolio, generates very high returns. The other thing, though, about the Permian, it's important to realize, and it's often overlooked, is the Permian averages, for us, our operated assets, about 15 kilograms of CO2 equivalent per barrel across the whole portfolio of Permian assets. And that's quite low compared to industry average global industry average. We also have a policy of not flaring in the Permian. So it's part of what Colin will talk about as part of our design and our plan, we put in gas offtake facilities. So we're not in a flaring or venting situation. And in fact, between 2013 and 2020, we actually lowered our North America methane emissions by 85%. And today, our Permian assets sit 85% lower than the industry average for the Permian. So we're one of the most efficient producers from a greenhouse gas standpoint, and high returns and free cash flow out of that asset. So it's really important. Colin, do you want to take...

Yes. I'll just talk about export capacity. But I mean, maybe just a high level, the way I think about the Permian is for the hydrocarbon there for the oil for the gas, the natural gas liquids, essentially the U.S. isn't big enough to absorb it all. So essentially, all -- you need to export alternatives for all of it. And then there's a whole piece of logistics of in-field pipelines to long-haul pipelines to export. And if you think about what does that look like right now because of the work that's been going on building pipelines, I guess, going back over 2 years ago before COVID, and then we had a demand drop and a supply drop in COVID. Right now, the pipeline infrastructure looks like it has capacity. So that's not the issue. The issue is export capacity. And the 2 things I think about is trying to get VLCC capability for crude. So there are multiple projects, but that essentially says how can you get the biggest ship, the lowest cost per barrel to get to international markets. And for gas, it's LNG plants, and they've been built out over time. Now again, just interesting, right now, they are all going full because gas prices in Europe, in Asia, in the 30s, gas price in the U.S. is about 4, there was a normal spread. But you've only got to go back 18 months, and I was to tell people guess prices are easy. They were $2 every way you look around the world when we went back 18 months. And if you look to the U.S. LNG plants, they were the swing players in the world, and they were running below 50%. So the world has changed really quickly. So we do look at it all the time, but the real question now is not where the market is today because markets today are screaming at you to try and get more LNG plants and get more gas out of the U.S. It's if you permit 1 today in and it comes on in 5 years' time, what do you think about that next 10 to 15 years? And so that's -- those are some of the things we think about. But generally, what do I think? I think we need more export capacity as the U.S.

Biraj Borkhataria, RBC. I have a question on returns...

Please state your name.

Biraj Borkhataria at RBC. I have a question on returns and the Permian figures you highlight are extremely strong. I'm just trying to think about that number greater than 30% in the context of the 12% group return target. If I assume downstream is and Kansas maybe roughly around the group level, that would suggest that a big chunk of your upstream or parts of your upstream are generating well below 12% returns. Could you just talk about the portfolio in 2026? What's holding that figure back?

When we look at the portfolio and we allocate capital, we're balancing 3 things in the upstream. We're trying to drive for the highest returns we can get. But obviously, if you only invest in your various best projects, you may not have then the free cash flow and the resource and reserve replenishment that we're going to need. So we're balancing all 3 of those against each other as we look across the portfolio. When I look ahead, our unconventional assets, and that's where 60%, roughly 2/3 of our capital is going into short cycle projects, which are not only unconventionals, but infill drilling programs, step-outs to existing facilities, things like that. We're seeing very high returns come from those, and they help boost the returns from some of the initial base projects that were put in. We also see an opportunity. The deepwater is a little bit longer cycle, but we can get some good returns out of those, and we have a nice queue of those in the Gulf of Mexico. We're seeing good returns coming out of the Eastern Med. Now with that new asset from Noble, I like the DJ Basin. All these, as we've focused our efforts on driving for more competitive performance as we've looked at becoming more capital efficient, it just takes time to work off some of the big long-dated capital that's in some of these big plants like the Gordons, the Wheatstones, the TCOs. And so they're lower on the return side, but they generate really strong cash flow, which is then helping us fuel our investments into the future in some of the higher return projects that are open to us. And that's how we kind of think about that balance and we think about it across the portfolio. Doug?

Doug Leggate from Bank of America. The Permian numbers have nudged up a little bit, it looks like. And I'm wondering if you can just opine on a topic as we've been quite front and center on, which is inventory depth for the nonoperated partners. Most of those folks talk now about routinely 10 to 15 years, which would suggest if they grow, they cannibalize your inventory life, you guys have a different set up. So when you look at your growth trajectory, about half your production is nonoperated, How does the mix between operated and nonoperated shift over the duration of your guidance? My follow-up, if I may, Colin, the question I asked Mike about de facto sanctions by changing the way you're trading. I wonder if you could address that.

So I don't see major shifts in that production profile. We've given those profiles before our company operated, the nonoperating, then the royalty production that we pick up. And of course, we've got a very advantaged portfolio from a royalty standpoint and that we hold a lot of acreage and collect a lot of royalty production. As we go forward, we're going to be moving from about $3 billion of capital investment this year total, up to about the $4 billion range. That's at the lower end of the guidance we gave you a couple of years ago where we thought it would be kind of in the $4 billion to $5 billion annual range. And it just represents the increased efficiency of the capital and the drilling and completion performance. But as we see these kind of improvements, others are as well. And our nonoperated, we study them, they study us. So we continue to see the industry gain. And I think we're going to continue to see that in the future. I don't think we're at the end of this road by any stretch in terms of being able to become more and more efficient in places like the Permian where you just do it over and over again. So I don't see in the near term any real change to that guidance we've already given you. Doug, I think it's going to be roughly in those proportions, but we're going to be seeing it all grow. Whatever we gave you, I don't have the exact -- I don't remember the number, and it kind of varies year by year, but it's -- we've got -- I think in this year, we're looking at probably roughly 7 rigs running for us. We get a lot more out of a rig today than we did a couple of years ago, so it's not a great metric. But just to give you a sense of proportion, we'll see a net of 10 rigs probably on the nonoperated side. So about -- that kind of gives you that 7 to 10 proportion.

Yes. No, if I think about market, Doug, I mean, I mean the way I think about it at the moment of what's going on is there's lots of concern. There's actually not much physical activity. So we've seen, I mean, crude oil is up over $100. So you've got -- I mean basic commodities was strong anyway. And so you've got this upward push on commodities in the futures market. But if you get to the physical markets, as of yesterday, and an update, gas is still flowing across Ukraine. So in the 5 days of war, that pipeline has still flowed. In the physical markets around crude, what's really happened is people have stood back and then we see it's a very kind of rational thing to do because you don't know whether that crude is going to supply and then whether you can pay for it. So we're just seeing people holding back. And so the question is how will it play out. I mean, some of the things we've seen short term, Mike did mention is Europe is blocked too, probably the biggest discount [indiscernible] Brent that we've seen. It was about $12 below when I last know. But the question is, is that real price? There's not much activity. We've seen some of it reportedly being picked up by India. That might be -- you could see trade flows happen, but this is all about thought of what the future. So you've got that Russian flow going to Europe. If it doesn't go to Europe, where will it go? If it goes, let's say, to Asia, that means that they would not buy a different barrel, which will then get displaced and go to Europe. So you could see this movement. The one thing you know about that movement is freight rates probably go up because the way my shipping people talk to me about let's say more tonne miles, but essentially longer freight routes. So you and you already see the shipping market slightly high. So those are kind of the big things that we're seeing. We're not seeing anything much really lack of activity.

What was behind my question commercial in terms of what we want to do opportunistically? And then there's the morality of avoiding Russia energy and [indiscernible] shareholder's position.

So we -- I mean, Chevron, as a company, we don't have a big exposure to Europe, which is where most of the Russia energy goes. So we're not in Europe as a big gas buyer. We don't have refineries in Europe. So really for us, that's not a big issue because we don't have much activity. Where we have our most activity, and Mike mentioned it, and it's in -- we just talked about Kazakhstan earlier is we have a pipeline that goes across Russia to get to the Black Sea. And we're still -- I mean, to [indiscernible] port we lift out in the Black Sea, we lifted it there at the weekend. We had a vessel offshore waiting, that trade route is still working. So we're focused on that. But apart from that, we don't have a lot of Russian activity in terms of buying for our refineries. So it's probably not that strong in our portfolio.

Jeanine Wai from Barclays. A first question, maybe going back to Sam's question, a related one on the Permian. Have you had any updated thoughts on taking any equity interest in midstream? The Permian is becoming a bigger part of the portfolio. You put out some higher targets today. Just wondering how you're looking to ensure the flow of that.

So Jamie, we do have midstream assets in the Permian. And we had some anyway, but we had more last year or 18 months ago, we acquired Noble. Noble had a midstream business, Noble Midstream Partners. We bought that in almost just May last year, so not quite a year ago and have integrated that into our system. So we do have pipelines that we own as well as pipelines that we have commercial deals on. So with all of that, what we're really looking for is how do we see this play long term? And for us, it's really making sure and it almost back to the high-level comments, we want to make sure there is enough pipeline infrastructure to flow from wellhead through to market centers or ports. And so some of that, we can own ourselves, some of that, we can do commercial deals on. And then we want to make sure that at the port, we can export and all of that value chain optimization is one of the things we talk about and Jay and my teams are completely connected. And what we're trying to do is optimize from the Permian Basin to all the connect that you have into the main pipelines and then figure out, are you best selling that molecule in the Gulf Coast? Or putting on a vessel and selling it to some different parts of the world where we have our global trading organization, optimizing? And we set that up, we have a team that looks at that, what do we think our long-term setup should be. So how do we think about this in 5 and 10 years. And then we have much shorter-term teams looking about how you trade that on a 30-, 90-day window. So we look at it on a very integrated basis, and we look at it across different time lines.

We're also looking at those returns and just what return can you get out of a pipeline versus commercial capacity that gives you the same rights and access with much less capital.

Okay. Great. Our second question, we're sticking to the Permian. Maybe for you, Jay. In terms of inventory, we're very focused on the sustainability of returns. And I think that when we look across some of your smaller peers, we feel good about maybe 3 to 5 years of Tier 1 inventory. Then after that, you kind of got to start getting creative. So any color on the inventory of the Permian, whether it be how much of your inventory you're going through for either the 1 million or 1.2 million to 1 point whatever million budget or -- or sorry, target. Or anything on how much of your inventory maybe breaks even at a certain level? So just looking for some color on that to see what the sustainability of the returns are.

Yes. We've given you some resource numbers in the past, and you can kind of look at what our current production under the curve. If you do the math, it's about 8 billion or 9 billion barrels. And you compare that against some of the numbers we've put out there in the past that are published. You can look at the 10-K. And when you compare those, you'll see we've got a lot of running room in the Permian, and that's without even looking at the enhancements that will continue to come as efficiencies continue to improve on both recoveries and investments. So I would say, for us, we've been very disciplined. Everybody is like, why don't you go faster? We didn't want to go faster. We wanted to go at a very deliberate pace where we can incorporate the learnings as we go and make sure we can deliver the returns and now the free cash flow as we go. And that's going to remain. So -- when we looked at that range, again, as Mike said, it's an outcome. It's not -- we're trying to hit a target. We're looking at the returns, we're looking at the activity levels that we believe we can execute and execute well, and not get ahead of ourselves in terms of continuing to incorporate learnings into our way forward. So I'm pretty happy with that curve for a while. Yes?

Phil Gresh, JPMorgan. Two questions. One is on the Gulf of Mexico, could you talk a little bit more about your plans there? Your targets for production are, I think, a little bit higher than I would have expected. So maybe you could just talk about some of the base decline management. How much production and capital are required? How much capital is required to get to that production? And then the other shale and tight is an area you've talked about in the past, there's a little bit of a discussion here today, but curious just how you're thinking about the growth aspirations in that area?

Thanks. I'll start in the Gulf of Mexico and then remind me, it's to move to the other shale and tight. I always forget the second question by the time I finish talking about the first. When we think about our Gulf of Mexico, we've tried to slow down and develop a queue of projects rather than trying to do a whole bunch in parallel at the same time. And it's the same thinking of let's get our facilities repeatable, so we're building the same thing over and over. We design it once and then we can use that design. We can engineer any issues out of it so that we have something that's going to be high -- more reliable from the beginning. And then we're also doing it so that our human capacity is not overrun to do it well. So you see projects like Whale, which is operated by others, but you also see Anchor. And then you can see Ballymore coming behind that. We continue to do drilling in the deepwater Gulf of Mexico, and we continue to expand that radius where we can tie new wells back to existing hosts, which really starts to leverage the infrastructure and boost the returns for us. The Gulf of Mexico across our entire portfolio is really carbon efficient. It's about a 6-kilogram carbon equivalent per barrel produced across all of our facilities in the Gulf of Mexico. And obviously, the newer ones tend to be on the even better side. So we're thinking of the Gulf as a good resource base for us. We have platforms like Big Foot, where we have still drilling capacity, and we're just managing a steady drilling rate, bringing capacity on to keep facilities full, kind of a drill-to-fill strategy, which tends to be very capital efficient. That's how I think about the Gulf of Mexico. So it's just a factory. We've got a queue of projects. We'll continue the exploration there as our expectation, but we're not going to try and grow dramatically just to grow. We're really growing as a function of the opportunities that we have there and how they stack up against other opportunities elsewhere. On the other shale and tight, this is an area that I'm really excited about because we've been able to take the learnings. Even when we had still Ambu, we were using learnings from there. That's where the zipper frac concept came in that we use in the Permian. We've taken different concepts from Argentina into the Permian and up to the Duvernay, Kaybob, Duvernay. But now with the Noble acquisition, we have the DJ Basin, and it is actually more attractive than we thought it was going to be when we did the deal. So that's really an exciting piece to add into our portfolio. And then we have the Argentina where we've picked up acreage in the conventional El Trapial area. We've now completed 7 appraisal wells in that area, and they're very promising. So we've got development starting to be planned and ramped up there. They benchmark their returns and their performance against our U.S. assets so that it has to compete in the portfolio just like everything else. It doesn't get a free path just to get production up, but we have some good resource barrels down in Argentina in not only the Loma Campana, but the El Trapial and there in Buena as well as DJ and still Kaybob, Duvernay, where we just keep a steady drilling program going.

Ryan Todd at Piper Sandler. Maybe a question on the Eastern Med. The ongoing geopolitical instability in Europe, I think it's clearly -- it's early days. We don't really know how it's going to play out over the long term. But it seems like on the margin, at least it's going to increase the desire to have more diversification of gas supplies into Europe, Eastern Med is clearly well positioned there. Can you talk a little bit about how you're thinking about the various options, about commercial opportunities? About interest? And how you're weighing things in terms of pipeline Egypt, LNG exports, various things and what are the various pros and cons of maybe some of the ways you're looking at it right now?

So maybe I'll start off with the resource side, and then I'll turn it over to Colin to talk more about the market side. From a resource base, it's a really nice-sized resource. And we have a base both at Tamar and Leviathan that both have expansion capabilities, and particularly at Leviathan. We also have Aphrodite, which is on the Cypress side, but adjacent -- physically adjacent to that whole region. And we're looking at options on how best to develop that and tie it into the infrastructure of the region. We currently supply it to Israel, and we've displaced a tremendous amount of coal for their power generation there. So it's had the effect of bringing down greenhouse gas emissions. We also sell gas into Jordan for power and then into Egypt. And so as Mike mentioned earlier this morning, we've just had another step forward on our opportunities to increase flows into Egypt. So that's another step in our progress. So I'll let Colin talk a little bit more about the marketing efforts and some of the different pathways.

Yes. So I'll just build on that. So we've got existing markets in Israel, Jordan and Egypt. And one of the questions is, can you do more? What does that look like? Can you just do more displacing coal for natural gas and make that work? And then there were LNG options. And so we are working LNG options at the moment, including floating LNG as an option. We're looking at a whole range of things. So we haven't got to a decision yet. But if I go back to your question, which is around one was how do you get this to Europe? Our view is if you get to LNG, you then put it on a vessel and then it's going to optimize to the most attractive market. So at the moment, that would be the way of getting it. So that's the way we're thinking about it. But we're currently going through all of those options, trying to figure out what's the most commercial outcome, which then helps unlock the resource that Jay just talked about.

And maybe on the deepwater, you talked about the Gulf of Mexico, and that's helpful. On a global basis, maybe can you talk about some of the deepwater opportunities you're seeing? You've seen less active on a global basis than maybe you've been at some point in your history. There seem to be -- globally, there are fewer players in the deepwater. Given your position of strength, does this -- are there opportunities that you're seeing for you to be able to get involved, whether it's exploration opportunities or positions and discovered resource for you to be able to grow your deepwater footprint more on a global basis, given the lack of to some extent that less competition than we've seen through too much of industry?

Yes. I wouldn't say that it's the competition driving it, so much it might increase the opportunities a little bit better to drive for higher returns. But we are still maintaining an active exploration program. We have scaled it back and been very disciplined about it, just like we have the capital going into our base and development programs. We have opened up new positions. We have 6 exploration blocks in Egypt that I'm pretty excited about. We're doing the seismic there and have some wells coming up. We've been drilling in Brazil and exploring some of the perimeters of that field of the basin down in Brazil. We've just acquired a couple of blocks in [indiscernible] that we have some interest in, and we're doing the seismic there. But we continue to look around the world at the best places to explore to make sure we're getting the most out of those exploration dollars that are in alignment with our future development plans. And so I see that being somewhat limited like it is now, but very disciplined and continuing at a good pace of activity that we can manage well. Most of the exploration is in the deepwater areas around the world at this point. Yes?

Roger Read, Wells Fargo. Coming back to maybe -- I'm going to ask 1 question, kind of 2 parts, so I will do the follow-up on you, but -- so you've got a fairly significant contracted portion and a spot portion. Is there anything that you would see changing in that? Or are you getting at this point request for changes, right, given what's going on? And then the other question, this would definitely be for you, Colin. We're watching oil prices obviously move up today, which tells us that even if there aren't direct sanctions, the financial sanctions are having an impact. Assuming the oil keeps flowing, what should we be watching over the next days and weeks that tells us some new intermediary on the financial side is stepping in that maybe take some of the heat out of the market? And who would typically be one of those intermediaries?

Okay. So I'll do the LNG one first. On the last earnings call, we talked about our portfolio and essentially, we said in terms of price exposure as a global portfolio where 80% linked to oil price, so these are long-term oil-linked contracts and 20% in the spot market. And that's roughly our portfolio, and it changed a little bit with seasonality and other things, but that's roughly are the way we're constructed at the moment. I just want to get the second question, are we getting people to ask us to think about that differently? And I think the question is with really high spot prices, are you getting more term customers saying, "Hey, I like that oil price, can I have more?" I'm not sure we're seeing a lot of that yet because you've got -- it's a really long-term thing. We do see and look the jargon is sloped. So people talk about the percentage slope of crude. Those bottomed out and have come back up. So we have definitely seen a moving back up of slopes, which is probably 1 indication that you might see some more of that. But the way I would answer your question directly, the high spot price has not yet turned into a lot of interest on long-term deals. So we're not seeing a lot of that yet. Sorry, there was a second part of the question, which I didn't -- it was about how do I think Russia play and willing [indiscernible] although that's a really hard 1 to answer. I mean if I go back to the first thing is at the moment, you're seeing just a lack of activity. So I think, over time, if -- I don't just stay with crude oil, Russian crude oil is going to flow, someone is going to have to buy it and you will move it somewhere. Those will be the things we look at. Now who buys it? Where does it go? I don't know. But those will be start of things to say the market then is beginning to move and then you'd look at this redistribution effect.

Paul, I think this is time for our last question.

Two questions, please. Jay, here's a quick one on Permian. I think your production target for this year is 10% growth. That actually make it maybe 2% or 3% lower than the fourth quarter. So is that just an ultra conservative estimate from your part or that there's some new things that we didn't realize happened in the fourth quarter? So if you can help us that to maybe bridge the gap because we thought with the higher CapEx that we will see progressively higher production from your asset? And the second one is maybe for Colin, A lot of your peers expect by 2023, 2024, probably 2023 late, that the Permian gas takeaway capacity will become an issue. And I want to see whether you agree on that? And if you do agree, do you think it should be for the benefit for Chevron to help to facilitate the [indiscernible] facilities. And whether that Chevron will really have a preference, whether you want to own the equity or that is really irrelevant, whether you own it or you have supply contract?

I'll take the first part quickly. When we put our plans together, it's always lumpy, especially with the nonoperator production coming in and when we get notified that it's online and all the rest, so there's some delays. If you look back at our chart, the actual chart, you see the red line kind of bouncing up and down, and some of that's reporting delays, some of that's real. But we thought we would end the year in 2021 about 5% lower as an exit rate than where we exited 2020 because of the pullback in capital. The reality was we came in a little bit higher than where we were in 2020. So we actually saw a little bit of growth in the Permian. As we pick up activity levels, I don't think this is a major shift, but it just represents we're a little bit ahead of the plan. It won't change how we allocate capital. We're still going to stick to this disciplined approach that we've had for a long time, but you're just seeing is a little bit ahead of the curve at this point.

Paul, I mean we probably think 2025, so we might be a bit later than your thoughts on gas when gas tightens up. But we do think the gas probably tightens up before crude. We think there's just more capacity in crude than and gas. And then how do we think -- I mean at the moment, we don't have equity in any long-haul pipelines out of the Permian. We've done all of those gas pipelines on doing deals with the midstream sector. So I mean, that's been our history. It doesn't mean that we don't look at it every time, but our history is doing long-term deals. And then I mean I think I answered the Gulf Coast LNG question before is yes, we continue to look at that. And the way -- the short-term market screens that you to do it, but this really is about what is your long-term view as market cycle and how do you think about that? So we continue to evaluate those.

So we're out of time for this session. We really appreciate your interest and your participation in not only today's session, but also as a company, and we hope we're able to answer your questions. I think we're going to take about a 10-minute break now, and then it will resume with Mark Nelson and Bruce Chin coming in to talk about downstream and chemicals. So about 10 minutes, and then we'll resume. Thank you.

Thank you. [Break]

All right. Good morning, everyone. I'm Mark Nelson. And with me today is Bruce Chinn, CEO of Chevron Phillips Chemical Company. We're here today to talk about Chevron's downstream and chemicals business. Let's start with demand. Diesel was first to recover to near pre-COVID levels with gasoline following closely behind. Our sales of both have now exceeded 2019 levels. While domestic air travel has been strong in many countries, full return of international air travel is still in front of us. When combined with refinery rationalization, we've seen margin recovery in the United States. While Asian margin recovery is expected over time as demand and capacity additions balance. We're optimistic about future demand. Demand for petrochemicals has been strong throughout the pandemic, boosted by increased sales for medical supplies, packaging, consumer goods and more. In the near term, we expect capacity growth to gradually pressure margins back down. Longer term, we expect middle class expansion and growing economies to support demand and margins. For the decade prior to COVID, our Downstream and Chemicals segment delivered returns that averaged near the mid-teens. With recovering product demand and an emphasis on what we control, we're targeting even higher returns over the next 5 years. To further strengthen financial performance, we're focused on managing costs lower and optimizing margin capture across integrated value chains. In 2021 earnings, they included more than $1 billion in self-help, and there's more to deliver. On top of that, we're targeting selective growth in renewable fuels and petchem. Volume recovery, more self-help, selective growth. all are expected to contribute to higher earnings and returns going forward. Our self-help actions are focused in 3 areas: value chain optimization, productivity improvements and reliability and turnarounds. We've expanded feedstock options across our refining systems, and we're using advanced data analytics and our leading brand position to optimize markets, volume and realizations. We've implemented a risk-based maintenance system that improves scheduling and delivers cost efficiencies in our non-turnaround maintenance programs. And with major turnarounds, we're expecting to improve costs in line with competitive Solomon benchmarks, while continuing to improve refinery utilization. We continue to make progress towards our 2030 renewable fuels targets. In renewable natural gas, we're growing the number of producing farms and Chevron's CNG network. Yesterday, we announced an agreement to acquire Renewable Energy Group, which is expected to build strength and accelerate growth across our renewable fuels value chain. We also recently signed definitive agreements with Bunge, we expect to commence the joint venture shortly after regulatory approval. And we continue to work with Gevo to potentially invest in the production of SAF with the execution of co-investment and fuel supply agreements expected in the second quarter. At our El Segundo refinery, we secured all renewable feedstock for the diesel hydrotreater and leveraging our capital-efficient approach to unit conversions, we expect that unit to have 100% renewable capability in 2022. And in the second quarter, we expect to close the acquisition of Neste's Group III base oil business and NEXBASE brand, which will expand our base oil offerings. And along with our investment in Nobie, scales our renewable base oil volumes with integration into our finished lubricants. And now I'll turn it over to Bruce.

Thanks, Mark. Hello, everyone. Chevron Phillips Chemical Company has a focused portfolio with world-scale facilities in the U.S. Gulf Coast and the Middle East -- these have low-cost feedstocks and a leading technology position. Our future investments follow the same playbook as we continue to work towards FID on U.S. Gulf Coast 2 and progress engineering for the Ras Laffan petrochemical project in Qatar. Costs always matter in a commodity business. And while margins have been strong for most of last year, we're taking actions to further debottleneck facilities and lower unit costs. And CPChem is accelerating advanced recycling, converting difficult to recycle plastic waste into high-quality feedstocks. Now we've achieved this with our certified Marlex, a new circular polyethylene product, and we've entered into multiple agreements to secure pyrolysis feedstock supply. So that's a quick overview of Chevron's Downstream and Chemicals business. Now let's move into the Q&A for this session. Please ask 1 question and limit yourself to 1 follow-up.

Good Lord. Paul, I think you were first. Let's go with Paul.

Paul Cheng, Scotiabank. Two questions. First, yes, on trading or you call optimization. Your European customer has been quite successful over the past 1 or 2 decades and utilizing trading as a profit center and enhance their return, believe or not, they think that had about 2% to the return. In contrast, U.S. majors, they tend to be more conservative in the way how you look at trading. So given the world that we are today, when you guys are looking at that, do you believe you should take a more aggressive approach in the trading and look at it similar to your European peer as a profit center -- if not, why you don't think it will work for you. . The second question maybe is for Bruce. CPC is probably one of the most well-run operation in the chemical side. and you guys have drive down costs and everything. So I mean from a self-help standpoint, is it really that much -- do we have much of the cost saving or the initiative that we can drive or that is really all about the market and also maybe expansion of capital.

Thank you, Paul. Well, if we go to your first question, I suspect you asked Colin the same question. There's a trade-off between volatility and value creation. And we've said fairly clearly over time that we think we have found that balance between flow optimize and trade and operating where we believe we have an advantage and then trading around those spaces over time. Do we believe there's kind of margin on the edges, if you will, certainly. But from a formal restating of how we're positioned in trading, I would not expect us to change. We like our position today because it balances risk and reward. On the CPChem side of the equation, I'm excited about some of the debottlenecking activity that's happening there. That actually is very controllable and you're making good progress.

Yes. First of all, thank you. I do think we're a pretty well-run company, too. So I appreciate that. We actually started a couple of years ago, something called Performance by Design, Paul. And it's really engaging the organization and instilling a continuous improvement in DNA in the organization. And just in the past, couple of years. We think we've seen kind of durable value improvement in our business that ranges from CapEx avoidance, which is more onetime, but just managing to constraints, really getting more out of the assets that we have on the ground. And we see more there just in terms of using data, digital technology and artificial intelligence to really optimize the facilities and bring value from those existing assets. So we're excited with what we've seen. We use our Solomon and Townsend benchmarks to understand by unit where our gaps are, and we're really engaging our engineers, scientists and the employee population in a very focused ideation around where we can make improvements and really look into continue to drive continuous improvement day in and day out. So we do think there's value there.

Yes. Paul.

Paul Sankey with Sankey Research. Could you talk to the maximum extent possible about your Bunge agreement? And could I continue to the potential for the project expansion on the Gulf, just more details on where we are with that.

So if you think back to our first time we discussed the Bunge joint venture, the concept for Chevron here is to secure soybean oil, feedstock or hard seed crushing capacity and working our way back into that value chain, so we can participate both in the crushing margin as well as the security of feedstock supply for our renewable fuels business. When you add that to the capabilities that we would be getting from the REG acquisition, you essentially get the seed oils and you get the waste oils from 2 experts in acquiring those type of feedstocks. And so we're very excited about how those play together for a portfolio of feedstocks that quite frankly, can weather margin profiles over time, similar to our conventional business. Specifically for Bunge, you'll recall that we're contributing $600 million and investing in 2 crushing facilities, 1 in Illinois and the other in Louisiana. They have the ability to expand those, almost double the crushing capacity of those, and we'll look forward to that by end of 2024. So we'll be able to take that straight into our facilities today, and we're looking forward to building on it over time. They've got a great capacity for what I'll call hard seed expansion in regard to third-generation feedstocks. So they're working on new technologies to drive what I'll call, cover crops and things like that as well.

I want -- you're speaking to CPChem projects, I assume then your question. And so if you recall, we paused those projects, we paused specifically U.S. Gulf Coast 2. And we're really driving off continued criteria of success around low-cost feedstocks, really very outstanding project execution and cost competitiveness. So they both have to be both the -- 1 in the Gulf Coast and the 1 in Qatar have to be low on the supply stack and certainly, good project execution as we go forward. And as we look at all those criteria, we do believe there are still good projects. We expect them certainly Gulf Coast 2 to go to FID sometime in 2022. We've taken the time, Paul, during this time to really, what I would call, do additional assurances, really work on derisking the risks that are in the project execution of a project that size. And so we're really feeling really good as we approach FID this year in 2022.

Mark, Phil Gresh, JPMorgan. First question, I was looking at the guidance slide on the net income for downstream relative to last year. And I know it's fuzzy bars, but I was just trying to understand, is there actually an increase in that guidance relative to last year? Because I know you have the renewables and chemicals wedge in there. And then for the chemicals piece, does that include the Gulf Coast second cracker that you're just referencing since it's supposed to be FID-ed in 2022?

Yes. So I'll go to the high level, and then we can kind of tell you what's in the big numbers. So if you think back 1.5 years ago when we started talking about how we were going to improve margins, we said a couple of things were required. We had to first have demand recovery. And you know that at least on most of our products, we are there. So mogas and diesel in our case, are clearly above 2019 levels. Jet has not yet gotten back. From a margin standpoint, we said we had to see sustainable mid-cycle margins. Now you all know we've touched mid-cycle margins in the refining business. The question is whether we are in a position where that can be sustained over time, especially in Asia. And then everything else was controllable. So it was self-help, renewable fuels and petrochemical investments. And so from a self-help standpoint, last year, we indicated that we had $1.5 billion by 2025. $1 billion of that was captured last year. So really good progress on that part of the equation. From a renewable fuel standpoint, everything that we've talked about other than the REG activity was actually planned. We had that all built into our plan. So that would be an incremental adjustment that we'll have to make in regard to future guidance. And then in regard to petrochemical facility, although we have not FID-ed the projects, we assume that in our capital in our business plan. Roger? You guys can just keep pass them out .

Roger Read, Wells Fargo. I guess really my first question, kind of looking at CPChem, the projects you have laid out for expansion. You've got 2 parent companies that have pretty, I would say, reasonably aligned financial frameworks. As you think about CPChem's obligations to its parent companies. Are there any things we should be paying attention to or expect as changes in terms of returns, managing growth, generating dividends to the parents, anything that's changed over the last couple of years. recognizing that CPChem came through the COVID era a lot healthier than probably the 2 parents did?

Well, what I would comment on is that in our plans, we clearly have the capability. I don't want to get too in front of my Board of Directors on this one. But we have the capability from a strong owners that support us very clearly with our growth plans to be able to execute projects and continue to maintain distributions to our parent companies. There's work still to be done on what balance we need there from an owner equity standpoint versus some level of financing, but that's still got to be worked through. We haven't landed on what particular model. We also have another partner that's also in the equation. -- and all of that has to be worked as we move forward.

So Roger, if I could add to that. I would say that from an owner perspective, we made those criteria for those crackers pretty specific in regard to being on the best part of the supply stack, which, of course, is the ethane-based feedstock. We said that it has to be cost and capital efficient. And the team has taken extra time to try to validate that, especially on U.S. Gulf Coast 2, and then they have to be able to execute it. When those criteria are met, we're willing to go. I think that's, as Bruce mentioned, that's likely for U.S. Gulf Coast 2 this year. Stepping back, I don't know if I would agree with the statement that CPChem was in a better position than Chevron. I can't speak for [ C66 ] coming out of the pandemic. But the ability to grow those same criteria will apply in all cases.

I was more referring to the margins that were earned more so than just absolute health. But second question is, obviously, the acquisition of REG really takes you a lot closer to the 100,000 barrel a day target by 2030. The rest obviously is more tied in with these agreements on soybean oil, feedstocks and other feedstocks. What is your line of sight on the roughly the additional, say, 40,000 to 50,000 that has to be added sort of post 2025 and is your view that, that's going to be predominantly renewable diesel or to be SAF or a combination of the 2? Too early to say. I was just curious kind of how that part should shake out?

Well, it's an interesting question. So bear with this, I'll take just a moment. So if you step back, I think you're talking about our 100,000 barrel a day target for renewable fuels capacity that we shared in the energy transition spotlight. And you could argue that the REG acquisition is really an accelerant. And I'll talk about an accelerant that's consistent with all the things we've talked about before. The first thing that it does for us is it immediately upon close, puts us at about 1/3 of the way to our target. And then within a couple of years, including our own actions that we had planned in our facilities, we'll be 2/3 of the way there in regard to capacity. But it's important to talk about kind of what's happening with this venture. In the past, we've talked about a few things being important. We've talked about feedstocks. We've talked about capital efficiency and flexibility, and we've talked about value chain. So from a feedstock perspective to Paul's question earlier, we are essentially acquiring some of the most gifted talent, the people that essentially started this industry, if you will, when it comes to acquiring feedstocks, especially feedstocks that are waste like used cooking oil, distiller corn oil and tallow. We already have the Bunge arrangement, which we've discussed. When you think about bringing those 2 things together, we have a portfolio of feedstocks that can allow us to play the margin game as well, which would from a feedstock standpoint, just like our conventional business. The second thing that we've talked about is capital efficiency and flexibility. I don't need to tell this group that margins normalize. And so building a system that can deal with that over time is really important to us. And so we have a Geismar facility that comes from REG that is essentially is like a complex refinery in the way that those of us who think about refineries, they can process anything. They've got 45,000 barrels a day of pretreat in their whole system. So they've got a lot of pretreatment. That allows them to chew up a lot of different types of feedstocks. The Chevron portfolio, as we transition and convert hydroprocessing units, they have a different type of flexibility. With a catalyst change, they can toggle from conventional products to renewable products. So as people struggle to do demand planning in the world that we have ahead of us, we're positioned to deal with all that. And then finally, we have the value chain. Both the Chevron and REG have strong connections to customers. We have, obviously, a very large presence in California, the most policy enabled market. And one of the synergies we've indicated is that we can help them place their biodiesel at the highest possible margin in our blending in the West Coast so that we can uplift their biodiesel a bit. So it's a -- from a strategic standpoint, it just really fits and it designs a portfolio that can win in any environment from our perspective. Sam?

Sam Margolin, Wolfe Research. A question that hopefully connects both your worlds on renewable naphtha. There's a large European peer who has a very aggressively high target for what the renewable naphtha market could be something like 30 million tons, and it's enabled because the underlying naphtha market keeps growing, right, whereas we don't know what's going to happen to underlying diesel and gasoline. So in the U.S., you don't care about that because you're using ethane. But just broadly, what do you think the opportunity set is for renewable naphtha to decarbonize the whole downstream.

Thank you, Sam. I'll make a comment about -- reminder about our portfolio. And Bruce, if you, you can talk a little bit about some of the opportunities in the whole concept of renewable plastics and petrochemical space. So remember, in our portfolio, we believe ethane advantage is the way to go. So our CPChem portfolio is focused on just on just that. And we believe that's the right focus long term. We do have naphtha exposure in our GS Caltex operation or mixed feed cracker in Yeosu, and they are naphtha focused. And given that they're integrated with the large Yeosu facility there. We believe they can compete well with the crackers in China. Over time, they could have some capacity for this, and they are investigating the ability to invest for that in the future. But we have a lot going on in CPChem about what I'll call the kind of the circular PE economy. And maybe you can share a little bit about that.

Sure. Sure. I mean, several years ago, we began to really accelerate our focus on that. Our strategy is really focused in ending plastic waste. We do our own part internally around that by really changing our mindset and our practices in terms of how we handle resin within our facilities. We're a part of the alliance to end plastic waste, which also requires a bit of investment. Chevron in that commitment basically committed $15 million over 5 years. We're using that in different ways, but 1 of the -- 1 area we're proud of is the Circulate [indiscernible] fund, which is really doing some good stuff in Asia. The second part of that is really the advanced circularity piece, right? And we were the first to announce production of a circular polyethylene resin, which takes that difficult to recycle plastics and puts it through paralysis processes and back into the front end of our crackers. We are investing in suppliers along that supply chain. We've made a couple of investments, 1 with Nexa Circular, MIRA Technologies in this race to create that feedstock and our supply chain that supports it. We're making sure that we're investing in a couple of different technologies. We're not clear always who's going to win that race. We've also invested in a fund called Infinity Recycle in Europe, which is focus there, but also looks at advanced recycling it looks to expand their footprint globally. So we think it's an important piece of the circular economy to have advanced recycling in our piece. We plan to try to produce about 1 billion pounds of that by 2030. And we actually made our first sale last month. So we see that starting to pick up, our customers are starting to demand and look for supply in that space based upon their customers' needs for recycled content. So it's an important piece for us.

So we'll watch the naphtha piece, the renewable naphtha piece going forward. The question is, as is always the case is with the customer -- and we have customers asking for things like renewable diesel. They're asking for sustainable aviation fuel, but at the right price. So that's why it's not quite there. In this particular case, the question will end up being the economics and where the customers kind of meet us in the value chain.

Demand elasticity. We're sitting here with oil now $1,600, $1,700. And so how do you think about where demand destruction levels lie -- and what products are you -- do you feel could be most vulnerable? And then how do you think about it from a geographic perspective because you do have a good footprint or a viewpoint into the world. So as we think about oil prices up here, do you see that as a risk to the sustainability of the product recovery?

Yes. Thanks for the question. If you step back and you think about traditional -- it's hard to use traditional benchmarks these days given everything that's moving around in the pandemic. But traditionally, motor gasoline would be the first thing to be hit because it's individual drivers. Products still have to go from point A to point B from a diesel standpoint. So I would see that perhaps not react quite as much. The motor gasoline side might have some degree of exposure. But it wasn't all that long ago that, that elasticity point would have been $5 a gallon. We have certain markets that have $5 a gallon today, and our customers still want to get out and get around and I think of California and how people are just starting to go back to the office for those people that commute. So we're actually hoping for a little bit of an uptick in that regard. But you could argue that you'd be approaching a point where we should be monitoring that.

And Mark, the follow-up is just the California market. How do you think about the refining market over the medium term as renewable diesel becomes a bigger part of the mix? Do you see that as a threat to refining margins? Or on the other side, are you taking capacity out of the market which point it's actually tightening up things like mogas.

Yes. Thank you. It's actually the latter. So you think about what most people project for California today. So you have some facilities that are not as competitive as the facilities, the 2 world-class refineries we have in California. People have been shutting down refineries or they've been converting entire refineries to renewal production. And so what that's done is most people project that over the next 5 years, California has a chance of going tight on motor gasoline, will hard to determine on jet today, given that we're still coming out of the pandemic from a demand standpoint. But I think you'll see the market actually tighten -- and one of our philosophies in those unit conversions that we were talking about earlier is the ability to toggle between conventional production and renewal production dependent upon what our customers are asking for and margins, of course. So our ability with a catalyst change to shift between the 2 is something that we think is a value proposition.

Doug Leggate from Bank of America. Guys, I wonder if I could ask you a macro question on prior to the Ukraine situation, there was already some emergence of a structural gap between international gas and domestic U.S. gas. And I'm thinking about it from the point of view of the impact on refinery operations, hydrotreating, energy and so on, when we think about mid-cycle refining is a structural step-up in international gas lead to a structural step-up in mid-cycle refining margins.

Yes. Interesting question. So in the short term, I would say we don't see it yet because it has -- it's all relative. It's not whether -- let's say, hydrogen goes up and crude stays. But when they move in parallel with one another, it doesn't really change our kind of refining spreads, if you will. So in the short term, I would say we can't see it move longer term we're watching just like you are. You could. We're not seeing that today, but you could. Please.

Lucas Herrmann at BNP Exane. 2 if I might. More value, less carbon. Just thinking about the broader marketing portfolio. So not just the retail business but also the sales that go through commercial. Decent margin, I presume, in retail, less margin in commercial. How do you think about the progress of that portfolio going forward and how you might look to shift it given your intensity ambitions, carbon ambition so on and so forth? And secondly, just refining, volatile, chemicals, volatile, more stable, the marketing income and lubricants income. But can you give us any idea or can you give me any idea of broadly what the marketing income in stable price environment typically contributes to the bottom line. And I guess, by marketing, I mean the retail aspect as well as the lubes aspect.

Yes. So if I go back to your comment about commercial, this is one of the reasons I'm so interested in bringing the REG family into the fold. As they -- in the renewable space, in particular, they have some unique end-to-end relationships with those customers. I think we'll be able to leverage that. Historically, you could argue that Chevron has focused kind of on the margin and that retail customer over time. We get to bring all of that together here. Now commercial customers, because of their scale oftentimes make competing for margin more challenging. But when you think about the products that they require longer term, so think about heavy-duty transport or marine or sustainable aviation fuel, those are the harder to abate type of segments. That's exactly what we do. So the ability to build a portfolio that efficiently produces those things, is the way to win over time because margins will be competed. They always are in this particular industry. To your second question, I'll keep it a little bit general here, but you hear us use the phrase value chain all the time, and it's because whether it's talking about the soybean and crushing margins or refining to terminals to service stations or to commercial customers, the margins always move. And our design is to try to have a relatively balanced value chain so that we can keep those things relatively stable over time, pandemics notwithstanding. So our intent would be to have a balanced value chain, right? So we get -- one way or the other from a margin standpoint.

Mark, just curious that with a [ flood ] of capital into the renewable diesel sector, I mean, the every month or maybe every couple of weeks, we have a new plan being announced. And from that standpoint, that even chemical, I mean everyone in the oil industry believe of the ethane advantage in the Gulf Coast. So a lot of capital has been falling into that. With margin is a function of demand supply, even if the demand is good, but supply you have over front. Is that going to become an issue? Is that something that make you maybe up at night that concern about your investment turn out that may be overinvesting. So that's the first question. The second question is a little bit more macro. You make an acquisition on the Pasadena refinery. But since that -- since then, that facility has been constantly having operating issue. I think recently that the facility was basically down for 2 or 3 months after an outage. So how much capital or time that you will need in order to bring that up to the Chevron standard.

Okay. So if we go to your first question, I think the fundamental comment, whether it's petrochemicals or renewable diesel is kind of the same thing. And this goes back to the idea that people have indicated capacity. They want to make capacity additions. Historically, not all of them happen, but they do happen, and we do see margins find that balance of supply and demand finds its equilibrium over time. The reason we continue to talk in the renewable diesel space about feedstock, capital efficiency and flexibility and value chain is so that we can win, if and when that happens because historically, it being the idea that maybe people overbuild and there's more supply available then it is absolutely necessary at that particular moment, so that we can win at that time. And the portfolio that we've created with feedstock, which is the broad perspective of renewables types of feedstocks, that capital efficiency where 1 facility can process anything that essentially will be a 20,000 barrel a day facility with the 45,000 barrels a day of pre-treat. And in these units within Chevron that can toggle between conventional and renewable fuels. That's a portfolio that can adjust to make sure we make the margins in those kind of environments. So I think that logic is why we always talk about making sure that these investments are capital efficient. And I think it's the same reason that we have those 3 criteria that I mentioned for our cracker investments. If we have the -- if we're in the best place of the supply stack, we are capital and cost efficient, and we execute well upon those projects whenever it is that they actually occur, we think we can win long term, even if the market, as it always does, in the chemical space, even if it cycles. Bruce, would you add anything.

I wouldn't anything? No.

So your second question was Pasadena, I believe. And so I'm not sure that we were down -- you may be talking about the FCC -- if the FCC, I'm not sure exactly what you were mentioning about being down. As we've mentioned, when we acquired that, we acquired it for a couple of reasons. There was the link to equity crude. There was the ability to supply our own fuels supply in the Texas area. And then there was the linkage to Pascagoula for intermediates. Those things are working as intended. I think we've talked before about the idea of taking it to a hydro skimming, which means you don't need the FCC. So a hydro skimming mode and then expanding our light tight oil capacity and maybe high grading our production output from the facility. I would -- and this will be a very capital-efficient investment. I would expect us to make a decision on that this year. Thank you. Please?

Ryan Todd at Piper Sandler. So maybe just 1 on -- how do you think about the kind of refining supply demand, refining margin outlook over the next 5 years, if your indexed demand numbers that you have there in the presentation are correct. And we've seen a relatively robust demand recovery, I think, probably stronger than expected over the last 12 months. The market looks relatively tight. So I guess I would just -- from your perspective, when you look out at trends in kind of refining supply demand in the margin environment over the next 5 years. What's your outlook? And then part of that trend that on the margin tighten things up is some of this conversion that we see of conversion of traditional refineries towards renewable facilities. Outside of -- I don't know if El Segundo has the ability to toggle back and forth outside of your El Segundo investment. What are your facilities -- what other of your facilities make sense over the coming years to potentially convert or co-process in that way?

Okay. Well, so first, I think everybody has been pleasantly surprised with the bounce of both motor gasoline and diesel demand. We certainly -- I know we have a strong brand, but I think the industry has been pleasantly surprised with how quickly things have come back for those 2 products. But we do need to -- Jet has not yet. I mentioned it in my prepared remarks, Jet is still to come, and we expect that over the next 12 to 24 months, you're seeing countries like Singapore and Australia starting to open back up. And so we're hoping that international travel will get back to its norm here over the next year or 2. When that happens, you have refineries operating in their more traditional modes, the more balance of yields. So we would expect that to occur. I would argue that refinery margins have gotten to mid-cycle faster than I would have expected. And the question is whether they can stay there. So they -- in the U.S. West Coast as an example, they have touched mid-cycle margins and they are starting to bounce around, again, Asia very briefly and will likely moderate. So I still think I do not believe that mid-cycle margin has been -- is restructuring yet. I believe that as we get to the 2024, 2025 times, we should hit that -- sustainably hit that mid-cycle margin. So that hasn't changed from our previous discussions. On the ability to convert units, so stepping back and talking about that capital efficient, very flexible manufacturing offering that we intend to have in El Segundo, just to remind everybody, we did co-processing. So we ran renewable feedstock through the diesel hydro treater and the FCC to allow us to test and see what allowed us to produce renewable diesel and sustainable aviation fuel. What we're now doing at El Segundo, given what we learned there is we're converting the diesel hydrotreater to 100% renewable capacity. So it will be able to toggle between diesel and renewable diesel. If you think about other facilities that we have, given our hydroprocessing capacities across the portfolio, you could argue that another California unit would likely need to be converted into the next 2 to 5 years, I would say. And that likely would be a hydrocracker. The hydrocracker is the 1 that would produce a sustainable aviation fuel diesel mix. Similarly, at Pascagoula, we have a choice to make as to which unit we would want to convert. But I would expect over time to have 1 or 2 units in the West Coast and 1 at Pascagoula and then we'll see how things develop in Asia as well. But we have the hydroprocessing capacity to do that. And when we do that, we consider the economics of the whole value chain to the questions earlier about supply and demand conventional versus renewable fuels.

Jason Gabelman from Cowen. Maybe another 1 on the refining supply-demand outlook. Asia, particularly China has a few large plants coming online, and you guys have a footprint there. And you've alluded to a couple of times at that margin maybe being a bit more challenged than in the U.S. So I'm wondering how you think about that new Chinese capacity coming online impacting not only the Asian basin, but the water global market -- does that capacity coming online just reduce other Asian product hitting the market? Or does it reduce the global refining margin outlook?

Yes. Thanks, Jason. I would think of Asia, although it's not completely contained. This is a global supply chain in many contexts. My worries about Asia are actually short term, but they -- because the international travel is so important to that portfolio over there. We are getting jet sales back to where they -- demand back to where it historically has been. I would expect that the Asian portfolio will be the last to get to mid-cycle margins sustainably from a refining standpoint, and it's because of there's more capacity. Inventory is bouncing in between and out of historic ranges. And so you have plenty of time -- you got plenty of inventory then China took quite a bit off the market, and now they're starting to put it back on. I would expect Asia refining margins to be a little bit challenged for the next year or so.

It's Biraj Borkhataria, RBC. I have a follow-up on SAF. Your comments around your customer willingness to pay for that product. I've heard that a few times from you and some of your peers. Can you talk about how wide is the gap between -- when you and your customer, are you -- is it close to a point where you can actually start to think about ramping up the capacity next few years? Or is it just there's a huge differential in and it is what it is?

Well, you probably remember that we are one of the larger jet suppliers today. So we have tight relationships with all the major airlines. And I wouldn't want to have you think that we're not selling SAF. So we have sold and we will intermittently sell sustainable aviation fuel to help the airlines and us test certain things. But until we get a little bit of policy support -- today, they get D4 RINs, I know you all know that, but it hasn't been enough to stimulate the market to lean heavily into that investment in the United States. And so when that develops over time, we'll have the kits that can easily be in relatively quickly because we're not changing operating practices at the facility, it allows us to, from a permitting standpoint to do those relatively efficiently, we would be able to meet that demand. But on your comment about, are they willing to pay up to a certain point today in regard to testing or doing small runs or things like that trials. Obviously, they're very good partners, but they want to be able to have a margin in their business as well. And I think we are at time, but I can't thank you enough for your questions, very thoughtful. Thank you for your time. [Break]

Good afternoon, everyone. I'm Jeff Gustavson, and with me today is Eimear Bonner, VP and Chief Technology Officer. I'm excited to share the progress made since creating Chevron New Energies. We continue to build momentum. In a few short months, we're almost fully staffed, including key external talent, and our teams are actively pursuing opportunities around the globe that will position us as a future leader in this space. Earlier, Mike reaffirmed the targets for our lower-carbon businesses. We believe that integrating with our existing capabilities and assets while investing across the value chain will enable us to deliver real value to customers and our shareholders. We expect to generate competitive double-digit returns and strong cash flow all while enabling greenhouse gas reductions later this decade. We're advancing hydrogen solutions for heavy-duty transportation and other harder to abate sectors, leveraging our capabilities, assets and customer relationships. We're nearing finalization of our entry into ACES, which aims to produce green hydrogen for dispatchable electricity generation with future opportunities to expand the supply of hydrogen more broadly across the Western U.S. We're advancing efforts in Richmond to support hydrogen transportation demand using excess gray hydrogen from our refinery combined with ongoing investment in associated production, distribution and retail infrastructure. We recently announced an agreement with Iwatani to co-develop and construct a network of hydrogen fueling stations in California. In the Asia Pacific region, we're collaborating with JERA, a global energy leader to explore regional production opportunities and the use of hydrogen and ammonia as a fuel in power generation. For carbon capture, we're building on decades of experience in handling CO2 to become a full-service solution provider enabled by foundational projects across the value chain and with partners to create shared value. We just announced an increased investment in Carbon Clean, a U.K.-based company with advantaged capture technology that reduces the cost and physical footprint required for carbon capture, minimizing site disruption and facilitating faster permitting. This partnership is an important step towards growing our future large-scale CCUS businesses. We expect to conduct commercial sized trials at our San Joaquin Valley facilities through partnerships with Carbon Clean, Svante and others to advance cost efficiencies enabled by technology. In the Asia Pacific region, our opportunity pipeline is rapidly growing through regional study work combined with direct customer and partner discussions. This has led to specific opportunities in both Australia and Singapore, with many more expected to follow. Like other lower carbon solutions, offsets will be needed to achieve global net zero. While not the primary strategy for reducing Chevron's operational carbon intensity, we anticipate utilizing offsets to help us with our lower carbon efforts. We plan to generate high-quality credits that are real, measurable and verifiable. And as global demand grows we're working to position ourselves as a portfolio supplier of offsets, providing customers with offset paired products. We're progressing opportunities to generate credits through scalable nature-based solutions like soil carbon storage, reforestation, and mangrove restoration. For all these new businesses, technology is a key enabler to accelerate our progress. I'll hand it over to Eimear to share more on Chevron's technology efforts.

Thank you, Jeff. In Chevron, we advanced technology through external partnerships, internal research and development and by deploying technology at scale. We have more than 2 decades of experience investing in start-ups, and we've trialed around 70% of those companies' technologies across Chevron. Recently, we invested in Hydrogenious, a developer of liquid organic hydrogen carrier technology. This is the potential to deliver affordable and efficient storage and transport of hydrogen, one of the more challenging parts of the value chain. Our internal R&D program includes [indiscernible] technology to create the feedstock flexibility necessary to deliver our renewable fuel targets. We have expertise and facilities that position us to move from proof of concept to pilot to commercial scale rapidly with modest capital investment, as seen at our El Segundo refinery, deploying and integrating technology across our assets enables us to commercialize leading solutions. For example, we're integrating technologies from partners such as Carbon Clean, Svante and others as we aim to scale carbon capture capabilities at lower cost. Solving energy challenges through technology is key to shipping the future energy system. And we have unique capabilities, assets and customers that offer a platform to accelerate our progress. Now let's move to Q&A. Please ask one question and limit yourself to one follow-up.

Doug Leggate from Bank of America. Jeff and Eimear, I want to be delicate in how I asked this question because it doesn't just apply to share on, it applies to your European peers and to a lot of others. And I'm thinking of it in the context of research and development. But the numbers that Chevron laid out at the New Energies presentation and what you've repeated today, suggests that cash flow is $1 billion at the end of the decade. That's not free cash flow. Even if I annuitize that and net against what you're spending, there's no obvious value creation, the NPV, DCF 0, 0, right? So how do we think about this? Is New Energies a value driver or is it a license to do business?

Good question, Doug. I mean, I think it's a little bit of both. Obviously, there's benefits in growing these new businesses on their own, right? There are benefits as we grow these new businesses, these new business lines in our existing decarbonization efforts and our traditional business. And that's a nice combination of having those 2 things. We've picked businesses that we see scaling significantly. We're focused on hard to abate sectors. We bring unique capabilities, and I could talk about the capabilities we have in every aspect of these businesses, and it's a long, long list. We have existing assets. In these businesses, we have existing assets that serve as customers for these businesses. And we have existing, obviously, a very large customer base in existing value chains, which relates to these businesses. When I think about the $1 billion, which we laid out at the energy transition spotlight, I wouldn't think about that too specifically. I think, yes, we expect these businesses with the skill sets we bring to them, very high growth, advancement of technology, appropriate policy support to be material businesses in their own right and to be profitable businesses and to generate attractive returns. And that's what the $1 billion represents. I mean as you saw just the acquisition that was announced yesterday, and I know you asked Mark quite a bit about that. These are businesses that we can grow to scale. And I think the $1 billion is just a starting point. We also laid out targets that went beyond 2030. They were not specific targets like the 25 million tons CCUS or the 150,000 tonnes a year in hydrogen sales. But we highlighted there's significant growth in these sectors later in the 2030s and certainly in the decades beyond. So hopefully, that helps you in how we're thinking about this.

[indiscernible]

Yes. We want these to be material, attractive return businesses. These are not just businesses we're doing to abate carbon. That's part of it, but they need to be businesses in their own right. Eimear, anything you'd add to that?

Yes. What I'd add is we focused our technology strategy on where we can reduce cost around these new businesses. So if I take CCUS, for example, we've got a number of pilots that we've planned in the next few years. In fact, one will start up this year. And we're really looking to lower the cost of carbon capture. So I think technology focusing technology on where we can reduce cost also helps with that generating the value and the returns and the profits that Jeff talked about. Another example I'd share was the hydrogenous one that I referenced in the presentation. Think about growing hydrogen business and being able to transport hydrogen safely and efficiently. That investment in hydrogenous will help us learn how to do that safely, reliably, but also cost competitively. A key part of that is using the existing infrastructure that we have rather than building new infrastructure. So those are a couple of examples of how we are lining up the technology strategy with the business and improving value and returns.

Jeff, Roger Read, Wells Fargo. My question is to understand the approach you're taking to some of these investments. So at one end, there would be just a complete scattershot. Let's find 30 or 40 things, throw a couple of hundred million dollars out there and hope for the best. The other side of it is you have really focused groups internally. They really understand all this, and they're -- you're making your arguments and working your way up to what you decide to invest in. Just curious how you've put that team together, right? I mean I think about your traditional businesses in oil and gas and chemicals, refining, they're well-established businesses. They haven't changed tremendously over the years. Suddenly, this is a big pivot. So I just kind of wanted to understand how you put the team together, how you get comfort in their recommendations and then knowing that some of what's been going on in the new technologies is going to fail, right? I mean some is going to work some won't. And since it's a little more VC oriented than just invest and grow a modest amount and fight depletion. I'm just curious how that all kind of came together and what your comfort level is? And then is there anything missing today that you'd still like to add?

Thanks Roger. It's a very good question. So on the first one, the approach, it's not a scattershot approach. But these are fast-moving immature businesses. You can imagine after we made the announcement that we made last late summer, early fall, that we were creating these new businesses. We've been working in these businesses, by the way, for a long time. But when we created a stand-alone centralized business, it was focused on these that had a mandate to focus on these. We get a lot of calls, right? And we have a lot of engagements with a lot of potential partners, existing and new customers. So there are a lot of opportunities that we're working through. The pipelines in each of these business lines have grown significantly from where we were last fall. We made a lot of progress in that space. But we need to be disciplined. We want to lead in this space. We're not doing this just to do it. As I mentioned in the answer to Doug's question, we need to generate attractive returns. We need to pick projects that can scale, projects that Chevron brings something to besides just money and something that over time can generate attractive returns. We stood up the organization last year. I'd say it's a relatively small organization in terms of Chevron scale, but a very high-powered, very talented organization. It's got a mix of both internal folks that we could draw upon, and there was plenty of interest around the company and coming into these new sectors and supporting us, and we're also bringing in external talent. I think you nailed it, though, with the culture question. There are parts of our traditional business that operates this way very quickly in an agile manner. You try a lot of things, not everything is going to work. We're very focused on building the right culture that can support these -- the organization that then can drive these businesses going forward. And it's not just within the New Energies organization, we get a lot of support and one of our sources of strength is Eimear's organization and the other technical expertise and help we can bring from around the company. You might speak to some of the support you're providing.

Yes. So the Chevron Technical Center supports all the segments, upstream, downstream, midstream. And so Chevron New Energies is no different. So we are applying the full breadth of the technical expertise, the leading experts that we have to Chevron New Energies. A couple of specifics, when you think about CCUS, we have history in CCUS. We have subsurface experts. So we have a lot of those resources dedicated working in teams with Jeff's organization. When we think about emerging technologies like geothermal that requires expertise in drilling and completions, we have the technical expertise in the center that's assigned to some of those opportunities. And so Jeff is fully leveraging the full extent of the Chevron Technical Center. And in pursuing not only the internal work, but then the tech ventures as well is looking at breakthrough technologies that might be part of the energy system. And we're partnering with companies like hydrogenous that I mentioned that also can help us with growing some of the businesses. So we're hand-in-hand -- working hand-in-hand and supporting technically on supporting from a technology perspective.

Paul Cheng, Scotiabank. Two questions, I think one for you and one for Eimear. For Eimear, just the technology one. And when we're looking at hydrogen, it seems like the new investment in -- we need is offering a different technology. But in the CCUS, is your technology any different than the competitor that you have, whether it's Exxon or that Shell, BP, Total, I mean all that we're essentially using the same technology. And if that's the case, then how you differentiate between Chevron to your competitor. And for Gust is that, if we're looking at the economic for the CCUS and hydrogen, I don't think they are profitable today. They are still emerging. How far is the gap in order for that to be economic, let's say, I call your January a 10% return. Is that gap will holistically within the next, say, 5 years could be bridged by the fundamental improvement in the cost structure or technology or that you will need a sizable improvement in the government support? And how big is that gap today?

Do you want to start with the first?

Yes. So maybe on CCUS, I think in terms of where we differentiate ourselves. First of all, we've got operational experience, right? So I think we have deployed -- developed and deployed technology in Gorgon, for example, that gives us insights in to injection, the safe and reliable injection for long periods of time, the movement of CO2 in the reservoir. So I think that operational experience is important. In addition to that, the pilots that we're doing, these technologies are different. And we also are thinking about how to integrate some of those technologies with other technologies. So per them, with, for example, CCUS, a concentrator technology with a capture technology. And so I think it's the way we approach our pilots and the asset base that we have, the diverse asset base that we have and the number of pilots that we've committed to puts us in a good position based on the plans that we have.

And I'll just add to that and then ask -- answer your second question. We do have a different strategy than some of our peers. We are focused on renewable fuels, hydrogen, CCUS offsets and emerging. And there's other technologies in emerging. We need to be careful. Geothermal looks different than some of the other ones that we're looking at. There are more -- my point is we bring -- we feel like we bring something to these new business lines. And so that's one potential differentiator in our strategy. I think it goes back to Roger's question. And it's hard to measure, but culture, we'd like to differentiate ourselves on culture. It's very, very important for these businesses, especially when you have large traditional businesses and now new businesses, within those that support the traditional businesses, but also new businesses and very different businesses than in the past. And partnership, we pride ourselves on being the partner of choice. It's part of our DNA. And we look to bring that. We want to participate across these value chains. We think we have a skill at integrating these longer complex value chains. We don't need to own every piece of the value chain that we can bring together partnerships that make these businesses work. We think we're very good at that. And I would also say, we will partner with some of our peers in this space, just like we do in the traditional business. This isn't something that any one company is going to figure out on their own. On the when are these businesses going to be ready? I mean, they're ready now. They'll start growing. They're growing rapidly as we speak. It really depends, Paul, I know you might not like that answer. On carbon capture, if I'm capturing a concentrated CO2 stream. And I've got sequestration, a ready-to-go sequestration solution. EOR is a great example of that where I can generate additional oil production revenue out of that, that's ready and that's economic today with very low level of policy support. But that's not what we're targeting. We're targeting harder to abate sectors where the carbon capture cost is higher. The streams are more diluted. We're trying to build large regional hubs, participate in regional hubs because scale is very important in carbon capture. The policy support will look different in that space. It may need to be higher initially to support investment in technology, investment in these projects to grow scale, lower the cost and then these businesses are more viable on a stand-alone basis potentially. Hydrogen is the same way. There are technologies that will make hydrogen -- that will reduce the cost of lower carbon hydrogen. But hydrogen, there's also a scale issue with hydrogen, there's a demand issue with hydrogen, enabling the demand for hydrogen is just as important as providing a low cost of supply. So I don't have a specific answer. We have ambitious targets in 2030 that show significant growth for our company in these new business lines. That should give you an indication of how quickly we see these advancing. And remember, we're looking to generate attractive returns as well, not just build businesses for business sake. Phil?

Phil Gresh, JPMorgan. I don't mean to be the dead horse on Paul's last question, but I do want to ask on CCUS. If we get an expansion of the 45Q to $85 a ton, in your opinion, is that enough to sanction something like these Houston Hubs or other hubs that they've been talking about? And then the second question is of the $1 billion of CFO that you're talking about by the end of the decade, can you give a rough split of that post the REGI acquisition? How much of that would you expect to be renewable fuels at this point between the acquisition, what you're doing organically? Can you get most of the way there already just from that? And then how do you think about the CCUS versus hydrogen or other components to that?

Sure. So on the first question, 45Q, obviously, we're watching that closely. One of the skills that we bring to these new business lines is our advocacy experience. This is something we do every day in our traditional business. Now we're doing it in maybe a different way, trying to enable the right policy -- balance policy. $85 has been talked about. Obviously, if $85 -- if the rate was raised from $50 a tonne for permanent stores to $85 per tonnage, like I talked about in response to Paul's question, it unlocks higher-cost CO2 streams for sequestration. Now the sequestration piece of this, there's still a lot of work that needs to be done there. You mentioned the Houston Hub. We're very happy to be a part of that. I think there's now 13 or 14 companies that are a part of that. It will take time to build that, find the right storage location. That's a mega storage project. You need more policy support to -- yes, to make something like that work. I think the policy support where it stands today only tackles a part of the overall equation. Remember, these are harder to abate sector. So the costs are higher. Technology will bring costs lower over time, but you need a balance between the right level of initial policy support to get things going, get investment started and that will drive these cost curves lower, just like it happens in our traditional business. On the $1 billion, I don't want to get really specific there going back to my comment that would -- it wasn't intended to be something to input into a model. It was more -- we do think we can achieve that, but it was more -- we mean it when we say we're growing these businesses to size. It -- but we did have some math that went into that, and you can think of it kind of in thirds, okay? Maybe 1/3 was renewable fuels. Obviously, the announcement yesterday might change that, about 1/3 would be in the carbon capture in sequestration space and about 1/3 in the hydrogen space. But that's very, very early estimates. I wouldn't hang too much on that. We'll continue to provide you updates as these businesses grow rapidly. Sam?

Sam Margolin, Wolfe Research. First of all, Hydrogenous is a great name. So congrats for finding that.

We'll pass that along.

Second -- so one of the things that European peers have done is they've merged their natural gas businesses with their low carbon businesses. And there's a lot of reasons to do that, not least of which is that natural gas does reduce emissions by displacing coal. But it's also an application for carbon capture and some of the other ventures you have in new energy. So I guess the question is how does Chevron think about that? It's a little bit difficult to decouple natural gas from upstream, but is that something that you see as a potential solution or something down the road where there's enough physical integration between natural gas and New Energies that it warrants a financial merger of the 2 streams within Chevron?

It's not something that's getting a lot of attention today. We launched these businesses. We have an organizational model that we decided on we're going to go -- we're very comfortable with that. We think that's the right model. We're going to work within that model for a period of time. Look, we always look at as these businesses advance and how these interfaces within the company, how those work, which are critical to making this work. If you can't draw those capabilities in effectively and efficiently, you're not going to be as successful. So would we look at changes going forward? Yes, something like that I think, would be very low on the list. We're integrated with our gas business already. One of the bullets on one of my slides was about a collaboration with JERA. And JERA is one of our largest LNG customers. I think it is our largest LNG customer in the Japan. We've got an existing value chain, LNG out of Gorgon and Wheatstone. They also have equity in Gorgon and Wheatstone. So here's an existing natural gas value chain managed by our natural gas and upstream groups. There's no reason we can't feed into that and already are the discussions we're having with JERA are about hydrogen, ammonia, carbon capture and the like. You put those two together, you can integrate without necessarily having -- making wholesale organizational changes. That's how we're thinking about that. Yes. Let's go right here in the middle.

Lucas Herrmann, BNP Exane. Natural Carbon Solutions or the offsets business, is it a profit center? Or is it a carbon offset center?

Yes, it's both. There are a number of demands for offsets that we do use them for compliance. You wouldn't call that a profit center, although you are avoiding a cost if you do not have the offsets available, but it's not a profit center in its own right for that use. We were going to look as we grow a portfolio of offsets -- high-quality offsets pairing those with existing products, which we already sell today. Is that a profit center? Can you get a little more margin? Can you -- is the price a bit higher, if you're able to provide a lower carbon products to a customer I hope so. And then there is -- as we grow this portfolio, and they're not being used for compliance or linked to existing products, you will have a trading business at some point. That's certainly in our remit and something we're looking at, working closely with our trading organization on that. I could see that developing into a profit center over time.

Jason Gabelman from Cowen. I had 2 questions. First on this hydrogen investment, which sounds like an investment in an e-fuels technology, correct me if I'm wrong, but it seems like that there's an obvious cost benefit where you're avoiding building out new distribution infrastructure that's worth like $4 a kilogram. So the benefit is very clear. Can you just talk about the offsets on the cost side, if there are any, and if you think e-fuels are the most likely way that the market is going to adopt hydrogen? And I have a follow-up.

Yes. I mean, tough question. I think e-fuels is certainly something that we're looking at. But our hydrogen strategy, Hydrogenious and there are other hydrogen investments. As you said, that will help unlock using existing infrastructure to distribute and transport hydrogen to make it easier for consumers to use it. You noted that's a much bigger part of the equation in our view than maybe the tech -- the production side of it itself. And that goes back to my comments earlier about how important it is to enable the right demand as well as bringing down the costs of the supply. And so we're focused on both, but our strategy using excess hydrogen at Richmond that exists today, again, just like the Australia to Japan value chain, an existing value chain. We can drop new products into that, constructing retail stations across the state over the next several years, but focus more on the heavy-duty transportation sector, which could include an e-fuels component. Right now, we're focused more on fuel cell technology and partnerships. We've got a partnership with Caterpillar, tackling the rail industry, partnership with Cummins on heavy-duty transportation and Toyota on light-duty passenger vehicles. Aviation and e-fuels, they're certainly there. It's something we'll keep working on. I'd see that further down the road from some of those other sectors. And as I mentioned, with JERA, power and industrial consumers. I think those are earlier adopters than maybe e-fuels, but that's something we'll keep considering. Follow up?

Got it. Yes, you mentioned Richmond Hydrogen, which is a good segue to my second question, which is it seems like refineries are prime areas where you can leverage existing assets to give you a cost advantage in kind of exploring New Energies. Can you just talk about some of the synergies there, maybe an underappreciated element of having an existing downstream footprint?

Yes. No, it's a good question. And I think it is underappreciated to have that volume. This is a significant volume of excess hydrogen at an existing asset, investment's already been made. It gives you a huge advantage. I mean that -- the cost of that hydrogen, the ability to test markets through a retail network across the state, but also the ability to attract the right partners into this space, our ability to sign up with Caterpillar and now BNSF has joined that joint venture because they know we bring something to this already. The ability to sign up with a Cummins with the Toyota and there'll be more of these as we go forward. A lot of that's enabled by the excess hydrogen that we have at Richmond today. The rest of our refinery system, we don't have the same advantages that we have at Richmond, but that's certainly something we'll build upon. And Richmond, looking at the other refineries, looking at opportunities to combine maybe a CCUS opportunity with a refinery, particularly in Richmond to be able to decarbonize the existing hydrogen stream is something that we'll look at. And it's not just -- last point, it's not just our refineries that we're working with. These businesses will rely more so over time on third-party businesses than they will on internal business, but we can use our internal businesses too as a starting point. Anything you'd add to that one, Eimear?

No, I think you covered it with the connection with CCUS. I think the CCUS -- and I'm talking about hydrogen here. So I think all the focus on CCUS and reducing the cost of capture and the pilots, the focus technology objectives that we have there will only benefit the hydrogen plants that you have as well.

Jeanine Wai from Barclays. You recently announced a pilot project with Project Canary in the U.S. And so just wondering how you see that market evolving and whether your discussions with customers are indicating that there is a willingness to pay a premium for certified gas?

Yes. And you might speak to some of the methane technology, Eimear as well. And I'm sure, Jay -- you talked to Jay about this also. No, but excited about that. For us, and this goes back to the offsets answer. When you have these discussions with customers, we look at this on an integrated basis. We might have an existing customer that we sell crude oil to, natural gas to, LNG to, products to. It makes it very easy as you started up these new businesses to go in and have a different conversation, a broader conversation about decarbonization. And in fact, it starts with some of the great work we've done over the past many years on carbon accounting, understanding what our carbon footprint looks like. That's a very important starting point here. There are some tools that we have internally. We've been running for years that can help get some others started down that journey. And then you might talk about, let's talk about CCUS, let's talk about our energy management program using renewable power, for instance, to power rigs and completion crews in the Permian. There might be a hydrogen application. You get down to the harder and harder to abate streams, and we have an offsets business as well, not to mention many other technologies in between. We are hearing interest from customers today. And we've made some announcements, an announcement with Pavilion in Asia Pacific to actually specifically calculate the carbon associated with LNG cargoes being sold into Pavilion. I see many more of those developing over time. And it goes back to Sam's question on natural gas for trading, in particular, a very important partner for us inside of the company. On methane technologies, I don't know what Jay had earlier, but Eimear might add a few more points on that.

Yes. I would just say that the Canary that you just referenced. I mean, this is just bringing transparency. It's by bringing transparency, the performance is really important to us in terms of being able to understand how we're performing from emissions perspective. We've deployed a number of technologies to enable us to detect and measure it. That next step is also to certify, verify and bring that transparency. So I think this project gives us that last step in certification and transparency.

We have time for one more, brother. Is this the last question. First and last.

So it's Doug Leggate from Bank of America. Eimear, direct air carbon capture, I believe you guys are also sort of seed investors to some extent, carbon engineering. I wonder if you could speak to the extent you can about how you see the viability of that business.

I would just say that we're exploring it. So I can't really talk about the viability with specifics. I think the direct air capture technology that you're talking about, may become part of the energy system, and that's why we invested. That's why we invest in a range of technologies through venture. So I think this for us to kind of learn about it as we partner with carbon engineering, and we'll take it from there. So again, it's about exploring a broad range of technologies that may or may not be part of the system. But that's kind of the overall approach.

Probably more focused on emissions to start. But I think of direct air capture technology, it has to be transported and sequester at some point. And so there's a customer base there. And so understanding what that technology is going is very important for our carbon capture business. Thank you for the question. I think we're out of time. And I think we're the last group, so this concludes our 2022 Investor Day. Really thank everyone for attending those that dialed in, and thank you for your interest in the company, especially. I hope everybody has a great day, and stay safe, and see you soon. Thank you very much.