Good morning. My name is Jen, and I will be your conference facilitator today. Welcome to Chevron's Fourth Quarter 2021 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. [Operator Instructions]. As a reminder, this conference call is being recorded. I will now turn the conference call over to the General Manager of Investor Relations of Chevron Corporation, Mr. Roderick Green. Please go ahead.

Thank you, Jen. Welcome to Chevron's fourth quarter 2021 earnings conference call and webcast. I'm Roderick Green, GM of Investor Relations. Our Chairman and CEO, Mike Wirth; and CFO, Pierre Breber, are on the call with me. 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 2. Now I will turn it over to Mike.

Thanks, Roderick. After the challenges of 2020, we began last year clear eyed about the economic realities we faced, and at the same time, optimistic about an eventual recovery. By the end of 2021, we had one of our most successful years ever, with return on capital employed approaching 10%, our highest since 2014; the successful integration of Noble Energy, while more than doubling initial synergy estimates; and record free cash flow, 25% greater than our previous high. 2021 was also the year when Chevron accelerated our efforts to advance a lower-carbon future by forming Chevron New Energies, an organization that aims to grow businesses in hydrogen, carbon capture and offsets, introducing a 2050 net-zero aspiration for upstream Scope 1 and 2 emissions and establishing a portfolio carbon intensity target that includes Scope 3 emissions and more than tripling our planned lower carbon investments. Chevron is an even better company today than we were just a few years ago. We're showing it through our actions and our performance, which we expect to drive higher returns and lower carbon. And we intend to keep getting better. Our record free cash flow enabled us to strongly address all 4 of our financial priorities in 2021, a higher dividend for the 34th consecutive year, a disciplined capital program, well below budget, significant debt paydown with a year-end net debt ratio comfortably below 20% and another year of share buybacks, our 14th out of the past 18 years. I expect 2022 will be even better for cash returns to shareholders with another dividend increase announced this week and first quarter buybacks projected at the top of our guidance range. We're optimistic about the future, focused on continuing to reward our shareholders while investing to grow our businesses and maintaining a strong balance sheet. We made the most of this challenging period, transforming Chevron through a well-timed acquisition and an enterprise-wide restructuring into a leaner and more productive company. In just 2 years, CapEx was reduced by almost half from Chevron and Noble's pre-COVID total. And operating expenses for the combined company in 2021 were lower than for Chevron on a standalone basis in 2019. The Noble acquisition and increasing capital efficiency enabled us to maintain a 5-year reserve replacement ratio above 100%. And 2021 was very consistent with that longer-term performance, driven primarily by additions in the Permian, Gulf of Mexico and Australia and partly offset by lower reserves in Kazakhstan, mostly due to higher prices and their negative effect on our share of reserves. For more on our strong financial performance, over to Pierre.

Thanks, Mike. We reported fourth quarter earnings of $5.1 billion or $2.63 per share. Adjusted earnings were $4.9 billion or $2.56 per share. The quarter's results included 3 special items: asset sale gains of $520 million, primarily on sales of mature conventional assets in the U.S.; losses on the early retirement of debt of $260 million, which will result in significant future interest cost savings; and pension settlement costs of $82 million. A reconciliation of non-GAAP measures can be found in the appendix of this presentation. Full year earnings were over $15 billion, the highest since 2014. Compared with 3Q, adjusted 4Q earnings were down $770 million. Adjusted upstream earnings were flat, with higher realizations offset primarily by negative LNG trading timing effects and higher DD&A. DD&A increased on catch-up depreciation for our interest in North West Shelf, which no longer meets asset held-for-sale criteria and impairments of certain late life assets triggered by updated abandonment estimates. Other items include additional taxes and royalties related to higher prices under certain international contracts. Adjusted downstream earnings were down with lower chemicals margins and volumes at CPChem and GS Caltex in addition to year-end inventory charges. The All Other segment declined due to tax charges. Across all segments, operating expenses increased in part due to higher accruals for employee bonuses and stock-based compensation. Adjusted earnings increased over $15 billion compared to the prior year, primarily due to increased realizations in upstream as well as improved refining and chemicals margins. Costs were up primarily on the acquisition of Noble Energy that closed in 4Q 2020, higher fuel costs and an unfavorable swing in accruals for employee benefits. 2022 production is expected to be flat to down 3% due to expiration of contracts in Indonesia and Thailand. These contracts are not being extended as we were unable to do so in terms competitive with our alternatives. Excluding contract expirations and 2022 asset sales, we expect a 2% to 5% increase in production led by the Permian and lower turnaround activity in TCO in Australia. We reaffirm our prior long-term guidance of a 3% production CAGR through 2025, and we'll share more about our long-term outlook at our upcoming Investor Day. I'll call out a few items on Slide 11. Full year guidance for the All Other segment excludes special items such as pension settlement costs. The All Other segment can vary quarter-to-quarter and year-to-year. Affiliate dividends are expected to be between $2 billion and $3 billion, depending primarily on commodity prices and margins. We do not expect any additional lending or loan repayments this year at TCO. Finally, asset sale proceeds are expected to be in line with historical averages. We've updated our price sensitivities to include natural gas. Also, our guidance for both earnings and cash flow sensitivities is now the same as we're likely to consume the remainder of our NOLs and other favorable tax attributes if prices remain higher. Finally, we did not receive our federal income tax refund last quarter and expect it later this year. Back to Mike.

All right. Thanks, Pierre. I believe 2021 was a pivotal year for Chevron, where we got better in so many ways. And we look forward to 2022 and beyond, confident in our strategy and capabilities that aim to deliver higher returns and lower carbon. We'll share more during our Investor Day on March 1. At this time, we expect to be at the New York Stock Exchange with a limited number of participants. The meeting will be webcast for all to see. With that, I'll turn it back to Roderick.

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 will do our best to get all questions answered. Jen, please open the line.

[Operator Instructions]. Our first question comes from Neil Mehta with Goldman Sachs.

The first question I had was more of a housekeeping item for you, Pierre, which is, in the quarter, it looked like LNG timing effects had a meaningful drag here. I recognize there was a lot of volatility, particularly towards the end of the month with TPS and JKM, but maybe you can break it down in layman's terms for us. What does that really mean and what happened in the quarter?

Thanks, Neil. About half of the timing effects in the quarter and first, we're showing a swing between 3Q and 4Q. We had a gain in the third quarter and a negative variance -- a negative absolute amount and a negative swing in fourth quarter. About half of the effects in the quarter were due to a negative inventory charge. So we had 2 cargoes on the water at year-end. They get valued into inventory at average annual prices, which were well below the purchase price because as you said, Neil, prices -- this was a rising price environment and prices rose in the end of the quarter. So that will reverse itself next year when those are -- or this year when they're sold at the higher prices that they purchased at. And then the balance of the timing effects are in paper mark-to-market effects. And as you know, the fit the paper, which is tied to physical cargoes gets marked to market where the physical cargoes are not. And so that creates a timing effect, which unwinds when the physical cargoes are delivered. We ended the year with a positive mark-to-market, but not as positive as what we had at the end of the third quarter. We added some JKM shorts during the quarter to balance our portfolio. We're still net long JKM. So any effects going forward will depend on the direction of future prices. And all this activity is really just geared towards managing our overall price exposure between our sales agreements and our supplies, which are a mix of both Brent and JKM prices. And just to put a fine point on the comment you made, these positions are not very large. But when we have natural gas LNG price movements that have gone from $10 to $20 to $30 an Mcf, it's causing larger timing effects than you would normally see.

That makes a lot of sense, Pierre. And then the follow-up for you is just on cash flow. Again, relative to consensus, it was softer. It does seem like there's some onetimers in there, maybe something around the timing of tax refunds and then where Angola shows up, but there's still a gap in there. So can you just talk about how you bridge to Street numbers in your mind, anything we need to carry forward as we think about next year?

Well, I'll cover the 2 points you made. We -- and I mentioned that we did not receive the IRS tax refund that we expected in the fourth quarter, we expect it sometime this year. We did receive a TCO dividend. There is a 15% withholding tax that comes off of the dividend. And we did receive the Angola LNG return of capital. It actually exceeded our guidance. By the way, the TCO dividend was at the high end of our guidance range. And the return of capital from Angola was above our guidance. But again, it shows up in cash from investing and not cash from ops because it's a return of capital. If you look beyond that, we do have, and as I referred to in our prepared remarks, we have certain contracts internationally that have additional taxes and royalties that kick in essentially when oil and LNG prices are higher, and we don't share specifics on our contracts. But as we talked about, we had extraordinarily high LNG pricing of $30, and then we also had oil prices that increase during the year. And then the last thing I'd say is we provided guidance on the third quarter call on our expected increase in earnings from LNG spot cargoes. And we gave that guidance in part because LNG prices increased significantly. And we said we expected to have fewer cargoes because our long-term contract takes were going to be higher during the winter from our primarily Japanese customers. We did not operate -- we didn't produce as much out of Australia, so we had fewer LNG spot cargoes. And again, that was an opportunity missed and that resulted in lower earnings and cash flow.

Neil, it's Mike. The one other thing you talked about what should you bear in mind going forward? As we've been in this fairly depressed commodity price environment, we've built up net operating losses in our business. And as we've returned to profitability, those have now been utilized and offset against taxes payable. As we work our way through those and in a strong price environment that could happen sooner rather than later, we'll be in a net taxable position that's quite different than what we were before as well. And so I think that's another point that may not be as evident in the quarter. But as you go forward, it's kind of a good news/bad news thing, I suppose, we're going to be more profitable, but it also means now we're going to have higher taxes payable.

Our next question comes from Phil Gresh from JPMorgan.

My first question is on the 2022 production outlook. Obviously, you had an extremely strong Permian production in the fourth quarter. It's about 70,000 barrels a day -- or 80,000 barrels a day, I'm sorry, above the full year average, and you're guiding to 80,000 barrels a day of new production in '22 over '21. So it seems like you can just get there from the Permian alone. But I'm just curious, are there other moving pieces that you should be thinking about on the new production element of the growth for '22? Or is there some conservatism there? Any thoughts would be helpful.

Yes, Phil, fourth quarter Permian does look strong. And one thing that we do see from time to time is with our non-operated joint venture position, sometimes the way production gets reported in by partners can result in a little bit of lumpiness in those numbers. But broadly speaking, the Permian is healthy and getting better. I think 2022 Permian production will be a little bit better than we showed at our Investor Day last March. And roughly speaking, up around maybe 10% compared to full year average in 2021. And that is the largest piece of what we would anticipate in terms of production growth next year. There is some growth in base and other primarily. As Pierre said in his comments, we've got lower planned turnaround activity at TCO, and we expect some more uptime at Gorgon. And then that's offset by a few asset sales that we would anticipate. So those are the significant moving pieces in production for 2022.

Okay. Great. That's very helpful. And Mike, I know you'll get in a lot more detail in March at the Analyst Day and looking forward to that. But just kind of looking back pre-COVID at prior analyst days, your framework was 60 Brent that you're using to balance CapEx and distributions in a fairly evenly balanced framework. Obviously, oil is at 90 now and maybe you don't want to give a guidance at those types of levels. But I am curious how you're thinking about what is the right way to look at the cash balancing framework? What price would you think is reasonable these days? As I know you like to manage the business through the cycle, not based on spot prices.

Yes. We will talk about that more in March, Phil. But our longer-term view on the pricing environment hasn't changed a lot. There's a lot of resource out there that can be produced economically at prices lower than what we see today. And our breakeven reflects that. And so we are in a period of time here where cash flow is strong. As we mentioned in our comments, the last 2 quarters have been the best 2 quarters the company has ever seen. And last year was 25% higher than the best year in our history. So we increased the dividend. Debt came down significantly, and we've guided to the high end of our share repurchase range. If we continue to see an environment like this, the balance sheet doesn't need to be a lot stronger than it is today. And we've already increased the dividend and we're going to be disciplined on capital. And so that really leaves one lever left. And I think over time, we're going to -- you should expect us to be consistent with our history, which is returning cash through share repurchases. And at least in an environment like this, we've got ample cash to do that and sustain that well into any kind of a correction that we eventually will see.

Our next question comes from Jeanine Wai with Barclays.

Our first question is on TCO. I guess now that you're through much of the winter campaign, is there any update on how FGP-WPMP and how those are tracking on cost and schedule maybe given your COVID protocols and efficiencies? And if you have any color on impact related to the recent geopolitical unrest, that would also be very helpful. Michael Wirth - CEO: Sure, Jeanine. Fourth quarter was really good execution on field productivity. We made terrific progress and that's carried forward as we began the year. We did have some impact during the unrest that occurred in Kazakhstan, but for about a week is the amount of time that it really cost us in the field there. We've remobilized everyone now and are back at full strength in terms of field activity. And we've got a highly vaccinated workforce, more than 90%. One of the highest rates of vaccination anywhere in our system in the world. And while we have seen Omicron cases appear in the workforce there, at this point, it's at a level that's very well managed, and it's not having any impact on field construction and activity. So we are continuing to make good progress. We have not made any change to our cost or schedule guidance and are overall at about 89% project progress and 82% construction progress at this point. So things have been managed really well on the ground by our team during a pretty challenging month of January.

Okay. Great. Good to hear. Our follow-up question or second question, maybe following up on Phil's question on the Permian. It's -- you guys had a really strong quarter, at least also compared to our expectations. You mentioned that 2022 production is a little better than where you thought it was going to be from your March Analyst Day forecast. So just can you clarify, have you accelerated activity there? Or is it really just all based on better efficiencies? And I guess given its importance to corporate growth in the medium term, are you taking any steps related to supplies or labor or equipment in anticipation of some tightening in the service markets over the next couple of years?

Yes. So let me speak first to activity. And then I'm going to let Pierre, who's now in charge of our supply chain organization, by the way, speak to any signs of inflation and how we're managing that. Activity in the Permian is really increasing aligned with the guidance that we've issued previously and spending this year up from $2 billion to $3 billion. Wells put on production, a little bit over 200 we anticipate this year, which is up about 50% versus 2021. And we'll share an update on all of these things when we see you in March. So I would say this is really very well aligned with what we've already guided to and indicated and reflects the ongoing efficiencies that we continue to see in the field and just the quality of this asset, which endures as we go through cycles like the one we just went through. It's really quite nice to have an asset in your portfolio that is this large, that's this flexible when it comes to capital and that we can demobilize, remobilize, not that we would intend to do this frequently, but when conditions call for it, we've been able to exercise that flexibility here over the last couple of years. So strong progress there. And I'll let Pierre comment on input costs.

Jeanine, we continue to manage our costs, we think, very well in the Permian and across our portfolio. Our capital budget, which we announced in December, expected some COGS increase, modest in the low single digits. And what we might be seeing a little bit more than that in the Permian, it's very manageable and we think we can offset it with efficiencies. So as we've talked about, although rates are up, they're still below where they were pre-COVID on rigs capacity in the industry for specific oil and gas, equipment and services is still below pre-COVID levels. So whereas we are exposed to labor and steel and certain other elements, cost elements that are tied to the broad-based economy, oil and gas-specific equipment services are still well under control and our ability to contract well, be a very good partner to work with, all gives us confidence that the little bit of cost pressure we're seeing is very manageable within the range of what we expected, and we intend to deliver our capital program in line with our budget.

Our next question comes from Doug Leggate from Bank of America.

So Pierre, I think your explanation about the dividend from TCO being a return of capital, I think that probably explains why The Street's cash flow numbers were too high. But my question is really about the go-forward portfolio leverage. So you obviously lose Indonesia, you lose Thailand, which I guess was gas. But you've got the Permian driving growth on a lighter recent history of PSC capital for the cost call standpoint. So my question is when I think about portfolio oil leverage for the go-forward outlook, how does that compare to the legacy portfolio given all those changes?

Our guidance on -- let me start by saying we've always been the most levered among the integrated energy companies. That's a function of the portfolio we've created over a long time, which tends to be upstream-weighted. And within upstream, we tend to be oil-weighted. And again, a big portion of our LNG is sold under oil prices. So whereas we were viewed as a defensive stock during some of the challenging times in 2020 and last year because of how we manage the balance sheet and how we're able to flex our capital program and manage our costs, we really are more of an oil play and we're much more levered on the upside. And we've shown that in last Investor Day, and we'll show that again in the upcoming Investor Day. In terms of our sensitivity, I mean, it's still around the same when you factor it all in. I mean, Indonesia was working its way to be a fairly modest portion of the portfolio. You are right over time with both Tengiz and the Permian that increases are weighting in some ways. But the guidance that we provided of $400 million of earnings and cash flow benefit from a dollar change in prices still holds.

My follow-up, if I may, is to go back to your one-off comments, the DD&A and the -- I guess, the timing effects. I'm just going to ask that the question for a little clarity. On the DD&A, it looks like there was some catch-up. What is -- how much was that because you didn't strip it out? I'm curious why you didn't strip it out. And then just real quick on the LNG, was there a shift in contract versus spot volume exposure that also impacted the quarter? And then that's it for me.

Yes, Doug. And first, just on your first question, so the return of capital was Angola LNG. TCO was a dividend withholding tax. But you're right, that part of that does not show up in cash from ops. In terms of DD&A, about half is due to the catch-up at North West Shelf. So we designated that asset as held for sale about 18 months ago. So you're capturing 18 months of depreciation all in the fourth quarter. We don't call the special item because obviously, it would have been in our underlying results if we -- it had been held for use during that time. And the other half are impairments that are tied to increases in abandonment estimates for late in life assets. So because these estimates, which is part of our regular updating process because these assets are very late in life, they don't have the production -- remaining production life or time to recover those additional abandonment estimates and therefore, that results in an impairment. So about half is the catch up and the half -- and those are both, I would call them onetime in nature. And in terms of the LNG, yes, there was a shift in fourth quarter to more contractless spot. We guided to that on the third quarter. And as I mentioned earlier, it was even more so. So in the winter months, our Northern Hemisphere customers tend to increase their takes under the long-term contracts. And then we didn't produce as reliably in the fourth quarter, so we had fewer spot cargoes. So what you're seeing, we did not benefit as much with the run-up in spot prices as we had guided to in the third quarter, and our weighting was more oil contract-related. Now those contracts are doing very well. Spot market goes up and down. But you'll see more exposure as we go forward.

Pierre, just I guess the point was the headline miss wasn't as bad as it looks. So thanks so much.

Our next question comes from Devin McDermott from Morgan Stanley.

So the first one I wanted to ask on is just CapEx. I think it's notable that you all came in for last year below the bottom end of your CapEx guide. And I was wondering if you could just talk a little bit more about some of the drivers of that CapEx beat. And then, Pierre, you mentioned before, I think, that you're seeing or assumed a few percentage points of inflation in the Permian. I was wondering if you could just broaden that out and talk about the inflationary trends you're seeing across the global portfolio and opportunities to potentially offset that as you think about 2022 spending levels?

So yes, sorry, the low single digits was really meant to be across the portfolio. And that's factored into our $15.3 billion capital program. But obviously, if you look offshore, those rig rates have stayed flat to down. And we do contract where we lock in rates for some services. We have price caps on some services. There's lots of ways that we work to mitigate our exposure to COGS. But -- so I would view it as low single-digits overall. Permian, perhaps a little bit higher, not nearly as high as numbers that I'm hearing from some others. We don't see anything in our cost that would be double digits at all. So a little bit very modest, presented to higher than what we had currently -- we had planned for and again, very manageable within -- by offsetting with efficiencies.

And on 2021, Devin, there's nothing noteworthy in the profile of CapEx and what it was that drove the ultimate outcome, which was a little below what we had guided to. There's a lot of inertia in some of these things and as we pulled the hand break pretty hard in 2020, we throttled a lot of things down. And as we start to bottom out and turn that back around a little bit as we will in 2022, this system just needs to adjust to that. And so I wouldn't call it anything there that's unique or especially noteworthy.

We have had, still, about half of the underspend is due to project deferrals like at Tengiz due to COVID and other impact and about half is capital -- greater capital efficiency and other cost savings.

Okay. That's helpful. And then separately, I wanted to ask on Australia LNG and Gorgon specifically. I was wondering if you could talk in a bit more detail around some of the recent downtime there. What happened and then what steps are being taken to ensure better uptime here in 2022?

Yes, I'll take that, Devin. Look, it's a point of frustration, no doubt. During normal rounds, we had an operator that spotted evidence that we had the risk of an operating issue at one of the units in the dehydration train. Nothing that was catastrophic or alarming but a sharp-eyed operator picked up evidence is something that as we investigated further, we felt it was prudent to take a quick pit stop to address this. And so that's been completed at 2 of the 3 trains, and they're all same design. So these things tend to show up across all 3 trains. . The third train is undergoing that pit stop right now and is also addressing a problem with one of the compressors that was identified, and this was an opportune time to make a couple of changes with that in order to reduce risk going forward. So we should -- we expect to operate reliably. We've done our first major turnaround on all 3 trains now, those are behind us at Gorgon. We do not have any planned turnarounds in 2022. And as we complete this last pit stop that's underway, our expectation is that we're going to have strong operational performance this year and see more production out of Gorgon than we did in '21.

Our next question comes from Paul Sankey from Sankey Research.

Guys, on your guidance, the volumes will fall this year, would you characterize that as you’re using a conservative oil price assumption and being determined not to raise CapEx? Or were there other issues around the concessions, particularly? And as a follow-up, could you accelerate the Permian, if you wanted to? Or can you talk about inflationary pressures that you might be seeing in the Permian as a matter of labor, steel, et cetera, et cetera?

Okay. Yes, on production guidance, Paul, I would hope this isn't big news to people. I mean it's -- we've long been public about the fact that we couldn't extend the concessions in Indonesia and Thailand on terms that would compete with other opportunities within our portfolio. And so this has been out in the public domain for quite some time. And so when you pull those out, we're at 2% to 5% and Pierre reiterated the compound annual growth of 3% out through 2025. And so this is very consistent with the guidance and the messaging that we've been trying to communicate for quite some time. On the question of, could you accelerate the Permian? In theory, the answer to that 5 years ago was yes. The answer to that today is yes. We've been very focused on execution, efficiency and returns. And as I said, we laid out in March of last year a profile that showed strong production growth, long plateau, strong returns and capital efficiency. We'll update that again here in the new year, but at March. But this is an asset that just continues to look as good as we've portrayed it to you, and we're not going to get out ahead of ourselves chasing anything as we bring activity back up from $2 billion last year to $3 billion. That's a 50% increase in capital spend. I mentioned that we're going to see a 50% increase in wells put on production in '22 versus '21. That is a meaningful step up in activity, and we want to execute that well. And so I don't think we're going to be tempted by the price of the day to put that at risk by doing more. And I think Pierre already addressed inflation. I don't know, Pierre, if there's anything else you'd like to say on either of those topics.

No. Thanks, Paul.

Our next question comes from Manav Gupta from Credit Suisse.

My quick question is your U.S. downstream results were down about $400 million quarter-over-quarter and we expected about $200 million of that to be chemicals headwind. But we also saw somewhere so what peers are doing is that refining was able to jump up and make up for it. In this case, it looks like both went down a little. And if you could help us understand what the maintenance in the refining system, what went on in U.S. refining because of which refining was also down quarter-over-quarter?

Manav, the -- there were a number of items we referred to, including year-end inventory effects. But the higher employee benefit costs really crosses all segments that would include U.S. downstream. So we had a very strong year. We expect higher employee bonuses and we accrued for that. And our stock ran up in the fourth quarter, and it's continued actually in the first quarter. And we have to do accrual for stock-based compensation that's tied to both the absolute stock price movement and the relative stock price movement because of how some of our incentive programs work. So that's in the segment, and I think that helps explain part of your question.

And a quick follow-up is you have a global footprint. Help us understand within your entire system, how you're tracking refined product demand, gasoline, diesel, jet as well, anything you could help us understand where we are versus before the pandemic started.

Yes. Manav, it's -- I think a lot of the data you see in the public domain is pretty good. We've got gasoline demand globally up higher than it was pre pandemic. Diesel at and perhaps slightly above, jet fuel continues to lag. The specific numbers can vary a little bit region by region. But broadly speaking, that's where we are. The ground transport fuels are at or above pre-COVID levels. Aviation is not and we still have an economic recovery underway. And we still have a lot of people working from home. We have people that aren't traveling for business and not taking international flights. And so even with the robust demand recovery that we've seen, there is still another lag to the demand improvement that is likely to occur here in 2022. And so I think the demand outlook is solid. And the issues, frankly, have been a little bit more on the supply side than the demand side.

Next question comes from Paul Cheng from Scotiabank.

So I have 2 questions, please. My -- if we're looking at your, I think, well-spoken slogans, lower carbon and higher return in here that Permian definitely is going to contribute to the higher return. Outside Permian, can you help us that to maybe bridge the gap or that you indicate what are the self-help that you guys will drive so that we could see a better return over the next perhaps 1 or 2 years? And the second question is, I want to go back into the Australian LNG as you indicated, I think, has been a source of frustration to management, as well to many people. And it seems like every -- I mean, the plan has only been on stream since 2016, 2015. And so really not that old, but we have all this kind of tiny little problem from different units coming up and niche one every time that they did, same story is all -- everyone there has problem. All the 3 train a problem because they're all under the same design or same manufacturer. So have you guys go into and do a thorough review on all the units and trying to see whether that has other potential time band that we need to face?

Yes. Paul, let me make a quick comment on the returns drivers, and I might ask Pierre to build on it and then I'll come back to LNG. Look, on returns, yes, Permian is highly accretive to returns because we get very, very strong returns out of the Permian, it's short cycle, and we're putting a fair amount of capital into it. We are reducing costs across our business. And as I indicated, we're running Chevron and Noble together today for costs that are lower than Chevron was stand-alone in 2019. So that is an improved -- significant driver of improved returns. We're working across the value chain to capture more margin. That's both in the downstream and in the upstream, a lot of self-help initiatives in the downstream. And so there are -- rather than think about pointing to assets, I would talk to you about the way we work and finding ways to improve efficiency and productivity across all of our operations is what are driving the improvement. And it's really rolling up your sleeves and doing this the old-fashioned way. And it's a lot of little things that you stay very focused on. Pierre, I don't know if you want to add anything else on drivers of return improvement.

We'll share more at the upcoming Investor Day, and we've showed it the last couple of investor days, right, what Mike talked about, it's constant margin, we obviously doubled; Noble synergies, we transformed the whole enterprise and reduced costs, working across the value chain and optimizing. As Mike said and Mark Nelson and the downstream has showed some ambitious self-help. And then capital efficiency, both where we're putting new capital and higher returns across the portfolio, and of course, as a lower return prior capital depreciates off. So we'll update you and everyone at our next Investor Day, but that's the playbook that we've been using, and we'll continue to use going forward.

Paul, to your question about Gorgon, you're right. It's not an old facility. And you're right, it has had more than its share of teething pains as we've been here in the first few years of operation. We have people all over this I mentioned earlier that it was a sharp-eyed operator on routine rounds that spotted something that we've addressed and that has averted the possibility of a more serious outage there. And we continue to do so. We don't have -- and a phrase you used, I won't repeat, but we don't have a big problem that's waiting to materialize that we've identified. And we have had strong teams of people from our upstream organization. We've brought people in from our downstream organization that have a lot of experience in these process facilities to work on reliability and mechanical integrity and address any of the things that -- frankly continue the things we've been fixing are things that reflect problems that -- the seeds we're sowing during the design and construction at a time when the industry was under a lot of pressure. And we've talked a lot about how we need to do better and our commitment to improve major capital project performance going forward.

Our next question comes from Ryan Todd from and Piper Sandler.

A question on the Gulf of Mexico. First of all, any update on the progress of potential deepwater developments in the U.S. Gulf of Mexico, including an anchor, which builds down like of a sanction, which seems like a lifetime ago. And the courts just canceled the result of a recent lease wholesale in the Gulf of Mexico. Maybe comment on whether you see any potential for incremental headwinds there on the regulatory front that could impact things in the future.

Yes. So a quick update on Anchor. We expect first oil in 2024, and that holds. The whole assembly is complete and commissioning is underway in Korea. We've begun drilling the first development well with a ship called the Deepwater Conqueror. It's a project that's got an attractive development costs, and that's even when you include some costs that are really onetime costs related to new technologies. Similarly, the Whale project, where we're not the operator, is targeted for first oil in 2024 and good progress there. And finally, Mad Dog 2, where we're also in a non-op position is expected to have first oil this year. So a number of projects that are making good progress and an important part of our portfolio. Lease sale 257, which was in the news. Yesterday, we were the apparent high bidder on a large number of blocks there that we found attractive. We're reviewing this judicial decision right now, and so I can't comment more about that. We're disappointed because these lease sales have been conducted successfully in the Gulf of Mexico for decades now and have resulted in us being one of the largest leaseholders out there with over 240 leases. It's a strong part of our base business. It contributes to energy security in this country. These are strong contributors to our portfolio and frankly, some of the lowest carbon intensity barrels that we produce. So we hope this is resolved in a manner that allows continued development and investment in the United States energy economy.

All right. And maybe just an overall question on refining. I appreciate some of the comments you made a few minutes ago, but in general, it feels like global product markets have tightened up quite a bit with the outlook looking and pretty encouraging for 2022. How -- can you provide some thoughts about how you're thinking about the setup for refining this year? What looks encouraging and what are some of the potential risks that you see to the outlook?

Yes. I mean I mentioned earlier the demand recovery, which is underway and which still has another leg to it. And we have seen margins strengthen across our portfolio as last year concluded. And so I think those are encouraging signs. Asia still has, I think, some risks. The approach taken by some countries, notably China, to how they've dealt with the pandemic may lead their economy to some risks if these variants continue to emerge. And then, of course, you have some other things in Asia. And again, in China, the situation within the real estate sector poses an uncertainty, I think, to some of the economic numbers there overall. So -- but broadly speaking, I think you're right, Ryan. We're seeing strengthening on the refining side, we're seeing utilization improve. And the chemical sector has continued to be strong, although it has been moderating from the highs early last year, still above mid-cycle as it's kind of trending back towards that. And so I think we're setting up for a stronger year in '22 than we saw in '21 across that sector.

Our next question comes from Alastair Syme with Citi.

I just had one question, and it's a follow-up to the question you made on returns. And I'll just really make a simple high-level observation that 2021 cash flow [$31 billion] ex working capital is almost identical to what was delivered in 2018 and then almost identical oil price environment. But of course, the payout ratio has risen considerably over the last 3 years. And my question is really what does the Board think it's seeing gives us the confidence to raise that payout ratio so meaningfully?

Yes. It's the capital efficiency is the big driver, Alastair. So you're right. The commodity price environments in those 2 years are pretty similar. Cash from ops, pretty similar, although there can be some moving parts in there that are not necessarily just commodity price. But we have capital spend that is significantly down from that period of time, which means free cash flow is significantly higher. And our belief going forward, our capital guidance going forward is $15 billion to $17 billion for the next 5 years. It has come down from $19 billion to $22 billion pre COVID. So that's a structural downshift. Our production guidance has not changed. And so what we have is a portfolio that is generating free cash flow and future cash flows in a much more capital-efficient manner which allows us to return more capital to shareholders. So that's a simple story.

Our next question comes from Biraj Borkhataria, RBC.

It's actually just a follow-up on North West Shelf and that reclassification there. Could you just provide a bit more color on the rationale for that? Is that a change in your intentions there? And obviously, the last couple of years is not a great time to be selling assets. I'm just wondering if that was a function of you not getting the valuation this you desired or something else?

Yes. Biraj, I think what we've said previously, we had an unsolicited offer on North West Shelf going back a period of time, which led us to an interesting conversation. And we want value -- we're not in a position where we need to sell assets to generate cash. But if an asset works better for somebody else and they see a different value equation that we do, that's certainly a conversation worth having. And so over the last period of time, we've been in a conversation like that. It ultimately has not led to a transaction. And so it's just changed the accounting classification for that asset. It's a good asset to generate strong cash flow. Obviously, we're in a market today where LNG demand is very high, and there's a lot of gas in Australia still to run through these plants. And so it's a nice part of our portfolio.

Yes. Just to echo that, I view it more as accounting-related than anything else. There's a number of criteria that need to be met for asset held for sale, and there's just one part that no longer has met. And so that's why we did the catch-up depreciation.

Okay. That's very clear. And then the second follow-up was on Tengiz. I think you previously mentioned the potential sort of loan repayments back to the parent. Do you have any guidance for 2022, given the current pricing environment?

Our guidance is no loan repayment, but also no additional loans. The dividend is included in the overall affiliate dividend I will make a point, we changed our guidance from focusing on the cash flow line, which is affiliate income less dividends and just focus on the true cash part. If you look back to that line, which again is the difference between income and dividends from our affiliates, it's still about -- our income from affiliates is expected to be about $2 billion higher than the dividends. But no loan, no loan repayment. We had a little bit of repayment last year. Again, we had our first dividend in a number of years in December. And in the current price environment, obviously, we expect strong dividends from Tengiz this year. It's a matter up to their Board. And as the project is completed and comes on, then the ability to increase dividends further and pay back alone, and we'll share more on the cash flow generation capability of Tengiz during our Investor Day.

Our last question comes from Jason Gabelman from Cowen.

The first one is just on international gas exposure. Even backing out this timing impact, it looked like the realizations were a bit light. And I thought it would be helpful if maybe you could talk through that international gas exposure, the different pricing exposures within that, maybe splitting it up between pump-based, LNG-based, fixed price or however you think about the commodity exposure within that production bucket? And the second question, thinking about CapEx, I think your message is loud and clear that this year you're going to be around that $15 billion and you're going to manage the business to that. But as we look forward and think about where you could ramp up spend, is that $17 billion high end of the range? Is that where you think the kind of ramp up in spending you could do in your short-cycle basins? Or is there, in theory, if oil prices stay at elevated levels, can you ramp up in your short-cycle basins even more? And once again, I'm not thinking about this year, in particular, but in the future, if we're in an environment where oil prices stay elevated.

Jason, I'll take your first question. So on our LNG portfolio, you can think of it about as an 80% oil linked, 20% JKM. That includes Australia but also West Africa, so Angola LNG and Equatorial Guinea. If you look to our international gas though, we have lots of other gas contracts around the world. As you say, some are fixed price, some are partially oil related with a lag. And so you won't see necessarily that direct effect. We have some that are low and, for example, in West Africa, that go to domestic markets. But if you look overall for the LNG, those 3 countries, Equatorial Guinea, Angola, Australia, 80-20 is pretty good. Australia now is a little bit higher because we had an additional long-term contract, but the West Africa LNG is largely spot-related and JKM or TTF price-related.

And on longer term CapEx, if I caught your question, Jason. Look, we get this range of 15 to 17. We've put out there. We're at the low end of the range. this year. Now that's a 30% step-up from where we finished 2021. And as I mentioned earlier, in a place like the Permian, it's a 50% step-up. So it's not a trivial change, but it's still a very disciplined approach to that business. And we intend to stay within that range as we've guided. Can we move around within it? Yes. Can that include additional short cycle, yes. And as we have -- as the project in Kazakhstan winds down, that opens up some capacity within that range to allocate capital to other high-return investments. And so we've got plenty of levers to pull. But I think the overarching message that investors should take away is we're going to stay disciplined on capital. We're not chasing price. We're improving returns and you can count on us to continue to do that. And we should generate very strong free cash flow in this environment.

Sorry, just to clarify, I think your guidance was on LNG. I was hoping to get it on the broader international gas price exposure.

That's just a mix of contracts, Jason. I'd follow up with Roderick. I mean I think we show our realization by country, but we don't have a short hand on how to characterize because it really is a mix of contracts in a number of countries outside the U.S.

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. Jen, back to you.

This concludes Chevron's Fourth Quarter 2021 Earnings Conference Call. You may now disconnect.