Chevron Corporation (NYSE:CVX) Q4 2022 Earnings Call Transcript

Chevron Corporation (NYSE:CVX) Q4 2022 Earnings Call Transcript January 27, 2023

Operator: Good morning. My name is Katie, and I will be your conference facilitator today. Welcome to Chevron’s Fourth Quarter 2022 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ remarks, there will be a question-and-answer session and instructions will be given at that time. As a reminder, this conference is being recorded. I will now turn the conference over to the General Manager of Investor Relations of Chevron Corporation, Mr. Roderick Green. Please, go ahead.

Roderick Green: Thank you, Katie. Welcome to Chevron’s fourth quarter 2022 earnings conference call and webcast. I’m Roderick Green, General Manager of Investor Relations. Our Chairman and CEO, Mike Wirth; and CFO, Pierre Breber, are on the call with me. Also listening in today is Jake Spiering, the incoming General Manager of Investor Relations, who will assume this position effective March 1. Jake and I will be transitioning together over the next couple of months. It’s been my sincere pleasure working with each of you over the last two years. Thank you for your questions, feedback and investment in Chevron. We will refer to the slides and prepared remarks that are available on Chevron’s website. Before we begin, please be reminded that this presentation contains estimates, projections and other forward-looking statements. Please review the cautionary statement on slide two. Now, I will turn it over to Mike.

Mike Wirth: Thank you, Roderick, and thanks, everyone, for joining us today. Chevron had an outstanding year in 2022, delivering record financial performance, producing more traditional energy and advancing lower carbon businesses. Free cash flow stood a record, beating our previous high in 2021 by more than $15 billion, enabling a strong dividend increase and the buyback of almost 4% of our shares. US production was also our highest ever, led by double-digit growth in the Permian. Growth matters when it’s profitable. Return on capital employed over 20% shows that our focus on capital efficiency is delivering results. And we took important steps in building new energy businesses. We successfully integrated REG’s people and assets into Chevron, combining the best of both companies’ technical and commercial capabilities.

And we acquired rights to pore space for potential carbon capture and storage projects in Texas and Australia. We had many other highlights last year, to name just a few, at TCO, project construction is largely complete, and we’re starting up the fuel gas system. Focus is on commissioning and start-up of the Wellhead Pressure Management Project by the end of this year, to begin transition of the field from high to low pressure. We announced a significant new gas discovery offshore Egypt, which could build on our growing natural gas position in the Eastern Med. And our affiliate CPChem reached FID for two world-scale ethylene and derivative projects in Texas and Qatar. 2022 was a dynamic year, with unique macroeconomic and geopolitical forces disrupting economies and industries around the globe.

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These events remind us of the importance of affordable and reliable energy with a lower carbon intensity over time. We don’t know what’s ahead in 2023. I do know that Chevron’s approach will be clear and consistent, focused on capital, cost and operational discipline, with the objective to safely deliver higher returns and lower carbon. With that, I’ll turn it over to Pierre to discuss our financials.

Pierre Breber: Thanks, Mike. We reported fourth quarter earnings of $6.4 billion or $3.33 per share. Adjusted earnings were $7.9 billion or $4.09 per share. Included in the quarter were $1.1 billion in write-offs and impairments in our international upstream segment, and negative foreign currency effects over $400 million. A reconciliation of non-GAAP measures can be found in the appendix to this presentation. Record operating cash flows in combination with continued capital efficiency, resulted in over $37 billion of free cash flow in 2022. The only other year Chevron’s operating cash flow exceeded $40 billion was 2011. Free cash flow in that year was less than 40% and of this year’s record. In 2022, Chevron delivered outstanding results on all four of its financial priorities.

Announcing earlier this week another 6% increase in our dividend per share, positioning 2023 to be the 36th consecutive year with annual dividend payout increases, investing within its organic budget despite cost inflation. Inorganic CapEx totaled $1.3 billion nearly 80% for new energy investments. Paying down debt in every quarter and ending the year with a 3% net debt ratio, returning record annual cash to shareholders through buybacks and exiting the year with an annual repurchase rate of $15 billion. Two days ago, Chevron’s Board of Directors authorized a new $75 billion share repurchase program. Now is a good time to look back on our execution of the prior programs. Over the past nearly two decades, we bought back shares in more than three out of every four years, returning more than $65 billion to shareholders.

And we’ve done it below the market average price during the whole time period. Going forward with the new program, our intent is the same, be a steady buyer of our shares across commodity cycles. With a breakeven Brent price around $50 per barrel to cover our CapEx and dividend and with excess balance sheet capacity, we’re positioned to return more cash to shareholders in any reasonable oil price scenario. Turning to the quarter. Adjusted earnings were down nearly $3 billion compared with last quarter. Adjusted upstream earnings decreased primarily on lower realizations and liftings as well as higher exploration expense, partially offset by favorable timing effects. Adjusted downstream earnings decreased primarily on lower refining and chemicals margins and negative timing effects partially offset with higher sales volumes following third quarter turnarounds.

The Other segment charges increased mainly due to accruals for stock-based compensation. For the full year, adjusted earnings increased more than $20 billion compared to the prior year. Adjusted upstream earnings were up primarily due to increased realizations. Other items include higher exploration expenses, higher incremental royalties and production taxes due to higher prices, partially offset by favorable tax benefits and other items. Downstream adjusted earnings increased primarily due to higher refining margins, partially offset by lower chemical earnings and higher maintenance and turnaround costs. 2022 production was in line with guidance after adjusting for higher prices. As a reminder, Chevron’s share of production is lower under certain international contracts when actual prices are higher than assumed in our guidance.

Reserves replacement ratio was nearly 100% with the largest net additions in the Permian, Israel, Canada and the Gulf of Mexico. Higher prices lowered our share of proved reserves by over 100 million barrels of oil equivalent. 2023 production is expected to be flat to up 3% at $80 Brent. After adjusting for lower prices and portfolio changes, primarily the sale of our Eagle Ford asset and the expiration of a contract in Thailand, we expect production to grow led by the Permian and other shale and tight assets. We remain confident in exceeding our long-term production guidance. Looking ahead to 2023, I’ll call out a few items. Earnings estimates from first quarter refinery turnarounds are mostly driven by El Segundo. Based on the current outlook, we expect higher natural gas costs for our California refineries.

Full year guidance for all other segment losses is lower this year due to higher expected interest income and again excludes special items such as pension settlement costs. The All Other segment can vary quarter-to-quarter and year-to-year. We estimate annual affiliate dividends between $5 billion and $6 billion, depending primarily on commodity prices and margins. The difference between affiliate earnings and dividends is expected to be less than $2 billion. We do not expect a dividend from TCO in the first quarter. We updated our earnings sensitivities. About 20% of the Brent sensitivity relates to oil-linked LNG sales. Also, we expect to maintain share buybacks at the top end of our guidance range during the first quarter. Finally, as a reminder in Venezuela, we use cost affiliate accounting, which means we will only record earnings, if we receive cash.

We do not record production or reserves. 2022 was a record year for Chevron in many ways. We look forward to the future, confident in our strategy with a consistent objective to safely deliver higher returns and lower carbon. We’ll share more during our Investor Day next month. Back to you, Roderick.

Roderick Green: That concludes our prepared remarks. We are now ready to take your questions. Please try to limit yourself to one question and one follow-up. We’ll do our best to get all your questions answered. Katie, please open the lines.

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Q&A Session

Operator: Thank you. Our first question comes from Jeanine Wai with Barclays.

Jeanine Wai: Hi. Good morning, everyone. Thanks for taking our questions.

Mike Wirth: Good morning, Jeanine.

Jeanine Wai: Before we get started €“ hi, good morning, Mike. We’d like to wish Roderick well in his new position, and we really appreciate all your time and help over the past two years. So thank you very much. Our first question, maybe just heading towards the buyback authorization topic. This week, the Board authorized the buyback authorization up to $75 billion, no expiration date, which is pretty large versus the prior authorization that had a four-year expiration date. We heard your comments on wanting to be a steady buyer of your shares across cycles and that you’re positioned to return more cash to shareholders. Can you comment on the decision-making process for getting to that $75 billion and maybe the choice to leave the authorization open in timing versus the prior authorization did have an expiration date?

Mike Wirth: Yeah, Jeanine, let me start, and then I’ll have Pierre add a little bit of color. We included a little information on this call looking back at our past programs. And as you saw on the slide 15 of the last 19 years, we’ve bought shares back lower than the market volume weighted average over that period of time. We look at the decision going forward in the context of the cash-generating potential of the portfolio, the outlook for the market environment, the strength of the balance sheet. And we don’t want to be authorizing a program every year. So, we talk to the Board about a multiyear outlook. So, the fact that there’s not an end date on it is only significant if you’re trying to do some sort of math and annualize this.

We think our track record speaks for ourselves and the steady, consistent way that we’ve done this. And so, we increased the rate three times last year as we saw the situation evolve, and we’re now at an all-time high with the rate of repurchases. So, the last thing you said it, but I’ll repeat it, in sized to maintain our program through the commodity cycle. We aren’t pro-cyclical. We’re not countercyclical. We’re steady through the cycle, and that is the intention. Pierre, do you want to add anything?

Pierre Breber: Yes, Jeanine. So, the authorization from 2019 was going to be consumed in the second quarter. It was also open. So, it did not have a defined time period. We just — will have consumed it. So, instead of having an authorization in the middle of the quarter, we’ll complete this quarter’s buybacks under the 2019 authorization, which again had an open time period, and then we’ll start the new on April 1st. So, it is similar the way it was done in the prior time.

Jeanine Wai: Thank you for that clarification. We appreciate that. Maybe our second question, it’s that time of year again, reserve replacement ratio, your ratio for 2022 was 97%. And we believe that compared to 112% last year, and then I think it was around 99% on average for the five years before that. So, our question for you is just — how do you see this ratio trending over time? And I guess the over or under bogey is probably 100%. Thank you.

Mike Wirth: Yes. So, it can move in any given year, Jeanine for a whole host of reasons, right? Prices, FID decisions, portfolio actions that we take to either sell or buy. And so, the one-year number is one that will move around. The longer cycle numbers, the one that you ought to pay attention to. Remember also, as we have this large position in the Permian we continue to develop. We can only book five years forward. And so, each year, we’ll produce out of the unconventional assets, and we’ll add another year’s worth of reserves on the back end of that. And so, if you were to look at the Permian unconstrained by that, you’d have a very different view. This year, we had some additions in the Permian and Israel and Canada and the Gulf of Mexico, as Pierre mentioned, the largest net reduction this year were Kazakhstan due to the contract terms and the effect of higher prices.

If you were to actually adjust that out, so we mentioned 100 million barrels where the price effect this year would be — think of it as 107% ex the price effect. And so, I do think over time, we intend to be in this business for quite a while and 100% is a number that you ought to expect to see that or greater over time. But in any given year or any short number of years, you might see something looks a little bit different.

Operator: We’ll take our next question from Devin McDermott with Morgan Stanley.

Devin McDermott: Hey good morning. Thanks for taking my question. First of all, Roderick, I wanted to echo Jeanine, congrats on the new role and thank you for all the help over the years and great working with you. So I wanted to focus in on upstream. And it’s good to see the continued progress on TCO and exciting to be getting close to the finish line on the expansion project there. You noted that WPMP is on track for commissioning and start-up later this year. I just wanted to first confirm that the second part of that expansion, FGP is still on track for ’24. And then just stepping back, could you just walk us through your latest expectations to the impacts on both TCO production, CapEx and then also affiliate dividends as these projects come online. Trying to get a sense of the changes in ’24 versus ’23? And then also, how you think about the run rate on both volumes and spending for that affiliate post FGP.

Mike Wirth: Yes. Devin, I’ll talk to the project and let Pierre talk a little bit to the financials. First of all, no change to cost or schedule guidance. WPMP is trending toward a beginning start-up by the end of this year. We’ve got a lot of work done. We’ve got a new power grid up and running and this was a power grid built back in the Soviet days. The control room is up and running, where everything comes into one central control room. All the production on gas injection wells are done, the gas injection facility is now in early commissioning. In just the next few days, we’ll tie in the fuel gas system to the first gas turbine generator, which is really an important milestone to test the first of the three GTGs, begin the process of powering up electrical generation capacity and commissioning boilers, steam and other utilities.

So, that all happens sequentially here over the next period of time, which leads to commissioning the pressure boost compressors in the third quarter and then converting the field from beginning the conversion from high to low pressure by the end of the year. A couple of things that will bear on production. We’ve got two planned turnarounds of the old processing trains. They’re called the KTL. There’s five of them. We had two turnarounds this year that are planned in the third quarter. So those will be down for a period of time. And then as those come back up, production may not fully recover on those two as some of the wells won’t resume flowing until we get to the low-pressure system. So, back half of the year, you’ll see a little bit of that impact.

And then as we move into ’24, we’ve got more of these high pressure to low-pressure conversions in the field and we’ve got FGP start-up first half of ’24. So you don’t see the full effect of FGP roll through, you get partial effect in ramping in ’24, and then the full effect will show in ’25. Cash will kind of follow that pattern. So Pierre, maybe you can talk about the pattern on CapEx and dividends.

Pierre Breber: Yes. For 2023, the TCO dividends are included in the guidance we provided, $5 billion, $6 billion, which is up from what our total dividends that we received last year. We did indicate that TCO has held a little excess cash during the course of last year just due to uncertainties that are going on right now. The CapEx was included in our December release. So it’s nearly half of the $3 billion of — affiliate CapEx, so that’s $1.5 billion. Again, you would expect that to continue to roll off next year. And then if you go back to our Investor Day, we showed that at $60 Brent post start-up in a full year of FGP production, that the free cash flow coming out of TCO on 100% basis would be $10 billion. And again, that’s a $60 Brent.

We’ll provide further updates as we normally do on Investor Day. But the takeaway, as we’ve said for a long time, now we’ve been investing in this project for six plus years through COVID, through the ups and downs, when it starts up, it will generate a lot of free cash flow. We’ll see that in the form of dividends, and we’ll see that in the form of paying back some of the loans that we co-lend into TCO.

Mike Wirth: Devin, just to kind of put a final punctuation on that. In our Investor Day last year, we showed in 2026, so once we get fully on the other side of all this stuff I just described, a 5x expansion in free cash flow out of TCO versus 2021. So it’s meaningful.

Devin McDermott: Okay. Great. Thank you very much for the helpful answer there. And thinking about this year, 2023 in more detail. You talked about 0% to 3% total production growth for the year, led by sale in the Permian. And last year, you had another strong one for the Permian unit volumes were up 16%. I was wondering if you could just talk through your expectations for that asset in 2023, whether or not you’re adding rigs there, overall activity trends? And then more broadly within that 2% to 3% range, what are some of the drivers that can move to the upper or lower end as we move through the year.

Mike Wirth: Yes. Maybe I’ll finish on — I think the second question is about overall production, and the first was about Permian. So our outlook for 2023 at $80 is flat to up 3%, so that post between 3 million and 3.1 million barrels a day. There’s a modest adjustment that relative to our Investor Day guidance. A couple of things driving that, some project deferrals like Mad Dog 2, which we thought would start up in 2022 and now looks like a 2023 startup. We’ve got some downtime, plans downtime that shifted from 2022 to 2023. And then our Permian growth would be a little bit lower in 2023. A couple of things. One, in 2022, we had the benefit of a lot of prior DUCs that had been sitting that came online and it boost early production in 2022, a little bit more.

And then we also are re-optimizing some of our development plans to factor in some of the things we continue to learn relative to interactions between wells and benches, how we space laterals and do single or multi-bench development. So our revised plan will have some deeper targets, a few more rig moves and a few more single bench developments, all of which brings that pace down a little bit. So that’s kind of at the highest level, what is behind the production numbers. We’ll talk about that more when we see you guys in a month here. And maybe I’ll stop there, because I did cover the Permian as part of that. Thanks, Devin. Katie, we can go the next question. Katie, can you hear us?

Operator: We’ll take our next question from Neil Mehta with Goldman Sachs.

Neil Mehta: Yes. Good morning team and congrats here on a good year. Hey, Mike, I guess the first question I have for you is around global gas. And maybe you can talk about how you’re seeing the market. There’s obviously been a tremendous amount of volatility and remind us again how you’re positioned from a contracted versus spot position? And then I have a follow-up on gas as well in the Eastern Med.

Mike Wirth: Okay. Well, high level, we certainly have seen a very unusual and volatile year in 2022, which has settled out here as we’ve come into the winter, primarily as we’ve seen a bit milder winter in the northern hemisphere than is typical. And as in Europe, the successful build of inventories for this year and the reduction of industrial demand have both resulted in an outlook that is less dire for the European economies, than it may have looked like several months ago. And so I think the market reflects all of that. You also have the fact that China has been — the economy has been slow throughout the year, which is — looks to be turning around. And so I think it’s good that markets have calmed. I mean the high prices really were creating a lot of stresses out there that are not good.

And I hope we see these prices stay in a more moderate range as we enter 2023. Our posture is largely as we’ve described it before, we’re primarily contracted on oil index pricing, biggest piece, obviously, out of Australia. We do have — we ran really well in Australia last year, a record number of cargoes and so there were some spot cargoes in the mix out of Australia, out of West Africa, we’ve got a little more spot exposure in Angola and now with Equatorial Guinea as well. But think of us as primarily oil-linked. And we’ve got some sensitivities, I think that Pierre has put out there, and we’ve reiterated some of those in the guidance today that should help you model these things based on your assumptions on gas prices.

Neil Mehta: Thanks, Mike. And that’s the follow-up. You have a large gas position in the Eastern Mediterranean, following the noble acquisition with Leviathan and Tamar and some discoveries out there as well. So how do you think about prosecuting that asset? Where does it fall in terms of prioritization? And how big can it be?

Mike Wirth: Yes. It’s a high priority. We took FID at the end of last year on a project to expand Tamar from — on a 100% basis, 1.1 to 1.6 Bcf per day. The first gas on that should come online in early 2025. We are working on development options to expand Leviathan. Those are still being worked and we should narrow the concepts on that later this year and reach some decisions in terms of how we intend to do that. The Nargis discovery, it’s just one well at this point, but it encountered a significant section of high-quality gas-bearing sandstone. So very attractive. We’re talking to our partner there about appraisal and development concepts that will follow. So that region — and of course, we’ve got a number of additional exploration blocks further to the west in the Mediterranean that we’ve not yet put any wells into but we’ve got seismic and we’re developing our exploration plans and you’ll hear more about that as we go forward.

So it’s a high priority. The region needs gas, both regionally in the Middle East, but also then obviously options to try to get that gas into Europe. And so the noble acquisition was really advantageous from that standpoint, and we’re optimistic about the prospectivity of some of these additional exploration blocks.

Neil Mehta: Very well. Stay tuned. Thanks, Mike.

Mike Wirth: Okay. Thank you, Neil.

Operator: We’ll take our next question from Doug Leggate with Bank of America.

Doug Leggate: Well, thanks, everyone. Roderick, I’d like to also pass on my thanks. You’ve transformed Chevron does Investor Relations. Thank you for all your help. Guys, I wonder if I could go back to the buyback. I just want to try and understand a little bit about the comment around really just how you think about the purpose of the buyback. Is this really about dividend management at this point? Because it seems to us that, if you take your Brent sensitivity into account, the run rate at the high end of the range puts you about a $90 breakeven on your oil price. And I’m just wondering if this is about value or about managing confidence in future dividend growth.

Mike Wirth: Well, let me try to be clear on this, Doug. We do not do buybacks to manage dividends. Dividend — absolute dividend load is an outcome. It’s not a reason that you would do buybacks. Our dividend growth expresses confidence in the ability to grow free cash flow at mid-cycle prices, and it is a long-term decision, a long, long, long-term decision. We haven’t cut the dividend since the great depression. Pierre mentioned, we’ve increased the payout 36 years in a row now. Buybacks are different. They signal confidence that we’re going to generate excess free cash flow, where we’ve got excess balance sheet capacity, which we have significant capacity in the current commodity cycle. And as we satisfy our commitments on the dividend, our reinvestment plans in a disciplined manner to grow free cash flows and maintain that strong balance sheet, we’ve got the capacity then to buy shares back through the cycle.

An outcome of buybacks is a lower absolute dividend, but it’s not the driver. And so, I don’t want — there should be no confusion about that. We’ve got confidence in our dividend increases, whether we’re buying shares back or not. We wouldn’t increase the dividend if we didn’t have that confidence. And so the two are not linked in that manner.

Doug Leggate: That’s very clear. Thanks, Mike. My follow-up is a bit unfair, given your Analyst Day is a month away, but I’m going to give this a go anyway. But — so if you made the point in — your balance sheet is in terrific shape, obviously. You’ve got a lot of capacity there. But also, if I go back to that sort of $90 breakeven, all I’m doing is taking that $15 billion run rate, $400 million a year and adding it to the $50 breakeven, $90. What does that say about your outlook for maybe stepping up growth capital? That would seem to imply that the growth capital of the $17 billion for the CapEx number is probably what we should expect going forward. Is that the right way to think about it, or should we wait until the end of the month, at the end of February?

Mike Wirth: Yes. I mean, we’ll talk about it more in February. I’m not sure I followed all your math there, but we’re growing. We had a 3% compound annual growth rate at $15 billion to $17 billion of CapEx in a market that’s not growing that fast. We’re growing well better than the overall demand for oil or for gas, which is growing faster than oil is. And so, we are growing production, but what we’re really focused on is growing returns and cash flow. And if we can grow returns and cash flow, the equation works. And so, I — we’ll be happy to talk about this more when we’re together at the end of the month, but — or at the end of next month. But we can grow cash flow; we can improve returns at the rate that we’re spending at. And so, I don’t know why there would be a question about our ability to do that and the production numbers and outcome of those decisions. It’s not the goal.

Doug Leggate: Appreciate the answers. Really glad. See you soon. Thank you.

Operator: We’ll take our next question from John Royall with JPMorgan.

John Royall: Hi, guys.

Mike Wirth: Good morning, John.

John Royall: Good morning. And thanks for taking my question. So maybe just kind of a spin on Doug’s question. So with the balance sheet at 3%, is there a point where you think of yourself is actually underlevered and I realize that’s a good problem to have. But if you ever got to that point with the mechanism be to get leverage higher by increasing the buyback, or how do you think about that generally is the 3% where you want to be?

Pierre Breber: This is Pierre. I’ll take that. Our guidance is for the net debt ratio to be between 20% and 25% and mid-cycle conditions. And as you said, we’re at 3%, so we’re much stronger than that. And that’s what happens in the short-term. So Mike has talked about our financial priorities. They’re simple. We’ve been consistent with them for a very long time. And three of the four are pegged. We just increased our dividend 6%. We have a 2023 CapEx budget of $14 billion. We’ve given guidance that keeps that CapEx flat over the next several years. And we have the buybacks at the top end of the guidance range of $15 billion. So swings in cash flow in the short-term will go to the balance sheet. And that’s because commodity prices and margins, we just were talking about natural gas prices and refining margins and things are moving up and down.

But over the long-term, those cash flows will be returned to shareholders. And so we want to do it in a way that is steady across the cycle. As Mike said, we don’t want to be pro-cyclical. And by the way, we haven’t, right? Our track record shows that over the past nearly two decades that we’ve been able to buy actually below what the market average price has been. So the intent is to, yeah, we’ll be a little strong balance sheet depending on commodity prices and margins and how strong our operations have been. But then over time, the cycle will correct and then we’ll continue buying back shares. We’ve said we could have a higher buyback rate right now. We’re sizing it at a level to maintain it for multiple years across the cycle. That means there’ll be a time period where we’ll be buying back shares off the balance sheet, and we’ll lever back up closer to that 20% to 25% guidance.

Thanks, John.

John Royall: Very clear. Thank you, Pierre. And just a follow-up on the TCO project. I was hoping you could give an update on the CPC terminal operationally and where that stands. And then what type of discounts are you seeing at that terminal right now? I think you called out a few quarters ago or maybe two quarters ago that it was $6 or $7 per barrel. I imagine that’s come in a bit. So where is that discount today? And how is that terminal operating?

Mike Wirth: Yeah. So last year, there was probably more news than there was impact on a variety of issues relative to the pipeline and the terminal. There was work going on in the late third and into the fourth quarter on the two of the three single point mornings. All that work is done. All three SPMs are operational today. There are no constraints on loading. There are no constraints on throughput on the pipe. Despite a lot of the things that people heard and worried about last year, the pipeline was very reliable. Our production was impacted less than 10,000 barrels a day over the course of the year. It was all a few weeks in March and April. And so everything there is running very smoothly now, and we don’t see any constraints.

Discounts have come in a little bit on CPC. In the immediate aftermath of some of the sanctions and changes related to Ukraine. We saw a trading range that was like $4 to $10 below dated Brent. And before the conflict began, it was plus or minus $1. We’re seeing kind of $1 to $3 discounts now. So maybe not quite at pre-invasion levels, but not as deep as they were immediately afterwards. And given the overall flat price environment and the way it has strengthened the impact to CCO is relatively muted.

Operator: We’ll take our next question from Roger Read with Wells Fargo.

Roger Read: Yeah. Thank you. Good morning.

Mike Wirth: Good morning, Roger.

Roger Read: Hey, good morning, guys. Just looking at, let’s call it, refined product demand. You talked about gas demand earlier. I’m just curious, as you look around the world, we’ve got positives moving away from COVID on a year-over-year comparison and then everybody’s got high expectations for the China reopening. I was just curious, as you look across your operating base, what you’re seeing there?

Mike Wirth: Yeah. Overall, Roger, gasoline demand, I’ll start there. Still just a touch below pre-pandemic levels, fourth quarter of 2022 maybe 2% or 3% below fourth quarter of 2019. If you look at diesel, demand is pretty flat versus pre-pandemic. Jet recovering, but still below and so at the highest level, we’re kind of still flattish to recovering from pre-COVID. I think that’s why there is concern that as China’s economy really does come through and return to a more normal level, that we could see increased demand start to pull on these markets again. You’ve seen announcements out of China about their intention. We see international flights and air travel now being scheduled at much higher levels than we’ve seen before long.

And if you see the kind of rebound spending and activity in that economy that we’ve seen in other economies around the world, that’s one of the things that could buoy the global economy and firm up demand for products. So, there’s still some variables in the equation. We’re not past the risk of recession and clearly, central banks are still tightening to slow things in certain parts of the world. So there’s some puts and takes. But net-net, this continues to trend in a recovering direction with the two biggest questions probably related to the two biggest economies, China and the US.

Roger Read: Always the big guys, right? A follow-up question to come back to the Permian, and I recognize the Investor Day coming. But Pierre, when we were at the sell-side dinner end of November, there was a lot of discussion over kind of the changing in the range and how that was really just a function of messaging more so than €“ overall change in the way you’re developing the Permian, kind of following from that to the comments about things a little different in the bench and the DUC comparisons year-over-year. You look at it as any different from the messaging at the end of November, or is this €“ is there something else here with.

Pierre Breber: No, nothing different. We’ll show that at our Investor Day. Again, we were in the middle of the range. You can see the fourth quarter number was 738. So that was strong. We had some learning’s, as Mike said, in 2022, and we’ve adjusted our plans to go to deeper targets and more single bench developments and that results in a little longer drilling times and a few more rig moves and we’ll update all that. And all that is obviously included in our production guidance. So we’ll continue to learn and adapt in the Permian. It’s a large royalty advantage position. It’s an asset that delivers higher returns and lower carbon. It’s a big source of free cash flow. Our free cash flow growth over the next five years is really driven by Permian, , Gulf of Mexico, a few other assets.

And it’s remarkable to have an asset that can grow at that rate and do it free cash flow positive the whole time and free cash flow growing the whole time. So, it will ebb and flow a little bit as we learn more, but what you’ll see at our Investor Day, something very consistent with what we’re saying today and what we said in the past.

Mike Wirth: And Roger, just to emphasize the point I made earlier to another one of the questions, we remain focused on returns and value, not on production. And so that is the — that’s what drives all of this. Thanks.

Operator: We’ll take our next question from Irene Himona with Societe General.

Irene Himona: Thank you very much for taking my questions which are both related. So, I will ask both at the same time. So, firstly, thinking about balance sheet strength, of course, the other use it can be put to is M&A. You’ve been very disciplined with your M&A timings, both with Noble and Regi . How do you see the current market in these two, let’s say, POTS legacy oil and gas versus low carbon? And then secondly, has the IRA Act perhaps changed your appetite for faster expansion in low carbon businesses, please? Thank you.

Mike Wirth: Thank you, Irene. So, we do have the capacity to do M&A. We don’t need to do M&A. And so, we’ll only do deals that are value-creating deals. You interestingly contrast the traditional oil and gas market with the new energies market. What I would observe is given commodity price strength in oil and gas, we’ve seen companies that previously might have been languishing from a value standpoint, strengthen. And I think there’s some optimism in the eyes of other companies about the future. And so, the bid/ask spread on oil and gas companies is maybe a little wider right now given the strength versus when we did our deal a couple of years ago. In lower carbon, with interest rates rising and spacs kind of receiving and the like.

A little bit of the kind of froth may have come out of that market, but they’re still some optimism in valuations there as well. And so, we’ll be very thoughtful and careful as we evaluate those. And there are a lot of companies out there that have got business models in this space. So, we watch them all. We will be back to talk to you if we have anything that’s interesting. Let me touch on IRA and then ask Pierre to add a little more color. The IRA will probably accelerate some activity in the US. There’s no doubt. Hopefully, what that does is it allows technologies to be de-risked. The cost of technologies to be reduced and the attractiveness of these investments to improve. A bill like that with kind of a grab bag of different policy incentives doesn’t necessarily change our long-term view on how we want to build businesses.

It does perhaps change the trajectory at which some of those businesses become more economically viable. And if that’s the case, that could feed through into our similar investment decision. But it’s kind of a second order effect rather than a first order effect.

Pierre Breber: And just to add some of the other important effects, permitting really critical for traditional energy, super critical for new energy, new technology developments, you’ve seen us make some investments on technology to reduce the cost of capture of CO2 and then scale, getting cost down. So it’s helpful, but it’s just one element, as Mike said.

Mike Wirth: Thanks, Irene

Operator: We’ll take our next question from Ryan Todd with Piper Sandler.

Ryan Todd: Thanks. Maybe if I could ask a couple on the downstream side. First, there’s been a lot of noise earlier this year about refinery maintenance activity looking to be well above average in the US, particularly in the first half of the year, especially amongst independent refiners. Your first quarter guidance seems to suggest turnaround activity in 1Q that’s reasonably light or at least not terribly heavy. Any thoughts on whether 2020 — year 2023 outlook as a whole for Chevron looks normal or heavy in terms of refining and maintenance. And then maybe more broadly, how you see general tightness in global refining markets this year over the course of 2023?

Mike Wirth: Yes. I would say it’s a pretty typical year for turnaround activity. We’ve got the FCC at El Segundo in the first quarter of this year, which Pierre mentioned in his comments. But there’s nothing unusual in our turnaround plan for this year. What you do see across the US and I think in some of the other markets are two things that are really kind of still echoes of COVID. One is you’re just seeing capacity go out of the system. And two, you see maintenance that was deferred during COVID is — had to be rescheduled and replanned. And so there’s probably still a bit of a bow wave of pushing through the system in some places of activity that needs to get done for safety and reliability and regulatory reasons. And so that could be driving some of the speculation. I can’t really comment on other companies’ plans. I’ll let you talk to them about that.

Ryan Todd: Okay. And then maybe on the other side of your downstream business on the chemical side, it’s clearly been weeks for the last little while. Looking forward from here, is the combination of lower natural gas prices and the reopening of China having any impact on how you see margins moving throughout 2023, or do you anticipate that oversupply keep things weaker throughout the year?

Mike Wirth: These tend to be long period cycles for the most part, Ryan. And so, at the margin, I think that’s economic growth and development in China is a positive. But you don’t slide into the lower part of the cycle quickly or easily, and you generally don’t come out of it quickly or easily. So these things track over a longer period of time. And so, I do think we’re — it feels like we’re kind of bumping along near the bottom here, but I don’t know that there’s a steep climb out as opposed to a gradual climb over time.

Operator: Thank you. We’ll take our next question from Jason Gabelman with Cowen.

Jason Gabelman: Good morning. Thanks for taking my questions. I wanted to first follow up on the affiliate distribution guidance because it is taking a step higher year-over-year, and it sounds like that was due to TCO having excess cash. Is that kind of $5 billion to $6 billion, something you can maintain assuming oil price stays stable until the project actually starts up until TCO FGP starts up or would you expect that to fall off after this year? And then my second question is on a different topic, Venezuela. I believe you have now boots on the ground there again. Can you just discuss what you’re seeing in terms of the health of the infrastructure there, the ability to ramp production and the desire from Chevron’s standpoint to participate in that? Thanks.

Pierre Breber : On affiliate dividends, there are two main factors why the guidance this year is higher than last year. You hit one of them on TCO, not held excess cash last year. The second big one is Angola LNG. You recall, a lot of their cash distributions were actually return to capital. It’s an accounting concept tied to whether you have book equity or positive book equity or not now, they’re in that space. So we expect most, if not all, of the cash coming from Angola LNG in 2023 to be characterized as dividends. It was cash either way. It’s just one shows up in cash from ops, the other one shows up in a different part of the cash flow statement, but that’s the second driver. And in terms of the direction, I mean, this guidance is kind of notionally at the current — futures curve around $80.

So it depends on commodity prices and margins. There are some downstream affiliates in there, the chemicals, obviously, in there. But we talked about TCO. I mean, TCO’s heading up, right. As CapEx comes down and production comes up, we expect more dividends out of TCO going forward. And then again, we have the loan that we also expect TCO to pay back during the next several years.

Mike Wirth: Yes, Jason, on Venezuela, we always did have boots on the ground. We just were very limited in where those boots could go and what they could do. The shift in the sanctions policy has opened up a little more room. It’s allowed us to work with PDVSA to put some of our people into different roles in these mixed companies there. So we do have a little more ability to have influence and involvement in some of the decision making. Your question about the state of the infrastructure, there’s been a lack of investments there for a number of years in the infrastructure reflects that, and it will take time for things to turn around. We have seen some positive production response already in the entities that we’re involved in.

They’re producing about 90,000 barrels a day now, which is up about 40,000 barrels a day since we saw the change in these license terms. So that’s been a good short-term effect. I’m not going to say you can extrapolate that, but it’s where we are today. We are continuing to work on the ground to expand production, but it’s too early to guide to anything. We’re also lifting oil and bringing it to the US. We’ve got a couple of cargoes coming into our Pascagoula Refinery. We’re going to be delivering cargoes to other customers on the Gulf Coast. And then the revenues go into a series of structured channels to pay expenses and other obligations. On the accounting standpoint, we’re using cost affiliate accounting. So we’ll record earnings only if we receive cash.

And at this point, I would say the cash flows are expected to be modest. So this is a step-wise change in the environment there. We’re going to go into it thoughtfully. It’s a six-month license, and it’s a dynamic environment. So we’ll continue to advise you as we learn more and as things evolve.

Jason Gabelman: Great. Thanks a lot for the detail.

Mike Wirth: You bet.

Operator: We’ll take our next question from Sam Margolin with Wolfe Research

Sam Margolin: Hey, good morning. Thank you.

Mike Wirth: Good morning, Sam.

Sam Margolin: I’ll ask about the Rockies. The Rockies is interesting. It’s a place where you could maybe add a little bit of activity to face your aggregate Lower 48 activity levels, but without some of the inflationary pressures and just infrastructure tightness in the Permian and inventory depth there is good. Is the Rockies a place where there may be a little bit of extra focus. And I ask that in the context of sort of the broader theme around your overall resource depth and production and all these topics that are sort of flowing into the broader conversation today.

Mike Wirth: Yes, absolutely, Sam. We got over 320,000 net acres there. Last year, we started out with one rig and one frac crew. We ended the year with three rigs and two frac crews working and the plan for this year is activity in that level. So it’s been a positive movement in terms of activity and production expectations there. It’s a really nice resource. It’s a low carbon resource. It’s a — we got a lot of this is powered off the grid. There’s been some permitting questions about this in the past. There’s been large areas done under development plans, and we’ve got permits well out into the future and continue to work that closely with the authorities there. So — it’s one we can talk about a little bit more at Investor Day. It’s a really positive part of addition to our portfolio out of Noble and the Eastern Med gets a lot of attention, but we’re very excited about the DJ.

Sam Margolin: Okay. And yes, just a follow-up. I mean, because obviously, between — I think you can surmise the reserve numbers getting some attention to the overall pace of activity and production trends over the long-term are getting attention. But we’ll get to this at the Analyst Day, I’m sure. But is there a way right now where you can kind of add it all up and size the Gulf of Mexico, other shale and tight, Eastern Med gas and just kind of frame that aggregate resource number against maybe what you see in the portfolio today as tail resource and just speak to a final answer around your organic portfolio and how it extends.

Mike Wirt: Yes. I might have Roderick work with you. So we’re clear on the question when we get to the Investor Day on how to compare and size things relative to the portfolio. But we said today in our press release that we’re very confident we’re going to exceed our 3% compound annual growth rate over the next five years. You can’t do that unless you get depth in the portfolio, which we have. And you got quality projects they’re moving along on a good pace. And so I’ll assure you that, that is the case. We will talk about this more at Investor Day, and you’ll have a chance to kind of go deeper into it with our folks.

Operator: We’ll take our next question from Paul Sankey with Sankey Research.

Paul Sankey: Hi. Good morning, everyone and Roderick, congratulations, all the best. Mike, I was a bit surprised by the major buyback announcement. Obviously, the $75 billion is very splashy. But within that, it seems that your guidance has remained that you’ll be in the $5 billion to $15 billion a year range based on the Q1 guidance. Is there — are you expecting to step that up, or is this a five-year authorization? And were you conscious that it would probably cause a lot of political backlash? Thanks.

Mike Wirth: Yes. So, Pierre answered the question earlier, it’s not a five-year authorization. It’s an open-ended authorization. It is — it’s our intent to maintain it across the cycle. I’ll just say that again. It’s actually aligned with our upside in our downside cases from the 2022 Investor Day and consistent with our track record of being in the market steadily buying $2 below the market over nearly the past two decades. And we could increase our guidance range, Paul. We need to be confident we could maintain that higher rate for multiple years across the cycle. And I think that you should read it as a signal of confidence and we’ll continue to talk more. We raised our buyback rate three times last year. So we’re not averse to doing that.

And I would just say stay tuned. In terms of the reaction to it, I think it’s perhaps been a touch overblown given that it’s an open-ended program, and we could have sized a smaller one and just been prepared to do another one sooner. Pierre said, we’re closing one out. We just looked at something that would last over a number of years, and we were trying to be splashy when we’re trying to create any reaction out there. We’re just trying to indicate the confidence we have in our cash generation.

Paul Sankey: Understood. And offset to that, Mike, you’re spending more on exploration. Could you just talk about the highlights that you see coming up in 2023. Obviously, we’re aware of East Med, but there’s other stuff out there and the spending has stepped up quite a lot, hasn’t it?

Mike Wirth: Yes. I don’t know if I describe the spending as being up quite a lot. We’ve got a nice portfolio that we like. And I’ll just touch on — you mentioned Eastern Med. We still have a lot of blocks in the deepwater Gulf of Mexico. We’ve got block in Suriname that we’re still working on and that are on trend with some of the things in that region. We’ve picked up acreage in Namibia that’s on trend with explorations in that part of the world as well. And so we got stuff in Brazil, we had stuff in Mexico that we acquired a few years prior to that. So we’ve got a nice portfolio of opportunities that we continue to work on. And we don’t go out and drill the wells until we’re ready to drill them. But it’s spread across a number of basins where there’s good working oil and gas systems. And the Nargis discovery is a recent example of what happens when you focus in those areas, and I’m optimistic that we’re going to see more of that in the future.

Paul Sankey: Thanks a lot.

Operator: Our last question comes from Biraj Borkhataria with RBC.

Biraj Borkhataria: Hey, guys. Thanks for taking my questions. So the first one is on the share count. Just going back to early 2022 of the period where you’re stepping up the buyback program, but the dilution from the employee options are offsetting that rule. So I’m just trying to understand, I know you took a charge today in the corporate line. Do you expect 2023 dilution to be a similar level to 2022, or should it be lower? Just any sense on that would be helpful.

Pierre Breber: We expect fewer employee and retiree exercises of stock options. That was extraordinary unusual in the first quarter. And it’s a zero-sum game. In other words, if employees and retirees do it early, there’s fewer to do going forward. But that will be up to them and the stock price performance. And the share buybacks, I mean, you just divide it, depends on what our stock price is. We give guidance quarterly, and I think you can do the math. It is confusing the difference between average annual share count and where we end, right? So we are clearly taking our share count down. But when you look at average annuals, that’s exactly what it implies. It’s an annual each day, but the trend is going down. Our buybacks exceed the issuances and we expect that to continue.

Biraj Borkhataria: That’s very clear. And then second question is just thinking about asset sales. Looking at your guidance, 2023 plans are fairly muted. And I appreciate that you’re basically at close to zero debt, so you don’t actually need to do anything but in a high commodity price environment, maybe counter-cyclically, you might want to accelerate something. So is this a function of just the limited cleanup needed in the portfolio or a view on bid-ask spread or anything else, just to get your view on the asset sale market at the moment? Thank you.

Mike Wirth: Yeah. So Biraj, we are a little lower than what our typical level of guidance has been a level of activity. Over the last decade, we’ve generated about $35 billion in asset sales. So that’s, say, 3.5%. There was some portfolio cleanup underway there that was needed to be done, and we get good value as we sold those. You’re always looking at your tail. There’s always — when you sell things off, there’s a new part of your portfolio and say, okay, this sits at the margin. And so you’re always challenging that. If we were to find interested buyers and some of the things that might fit better for others than they do for us, we could transact on that. This is — the guidance that we’ve got right now and the things that are underway and in process is what we’ve put out there, and we’ll update you if there’s any changes to that.

Pierre Breber: And the only add, Biraj, we don’t do asset sales to raise cash or to manage the balance sheet. We do it based on what Mike just said, high grading of the portfolio where we can get the best returns for capital projects that can compete for capital, some of the impairments that we took in the fourth quarter are a result and outcome of projects that are good projects. They’re just not good enough to clear the bar. So it does ebb and flow a little bit as Mike has said, but I just want to be clear, we do it as part of our capital discipline and having driving higher returns and lower carbon. It’s an outcome of that. It ebbs and flows. It’s a little low this year. We set it to go back higher in future years.

Roderick Green: Thanks Biraj. I would like to thank everyone for your time today. We appreciate your interest in Chevron and everyone’s participation on today’s call. Please stay safe and healthy. Katie, back to you.

Operator: Thank you. This concludes Chevron’s fourth quarter 2022 earnings conference call. You may now disconnect.